U.S. patent number 5,592,438 [Application Number 08/108,958] was granted by the patent office on 1997-01-07 for method and apparatus for communicating data in a wellbore and for detecting the influx of gas.
This patent grant is currently assigned to Baker Hughes Incorporated. Invention is credited to Frank L. Gibbons, James V. Leggett, III, Steven C. Owens, Ashok Patel, Louis H. Rorden.
United States Patent |
5,592,438 |
Rorden , et al. |
* January 7, 1997 |
Method and apparatus for communicating data in a wellbore and for
detecting the influx of gas
Abstract
A transducer is described especially for use in providing
acoustic transmission in a borehole. The transducer includes a
multiple number of magnetic circuit gaps and electrical windings
that have been found to provide the power necessary for acoustic
operation in a borehole while still meeting the stringent
dimensional criteria necessitated by boreholes. Various embodiments
conforming to the design are described. Moreover, the invention
includes transition and reflector sections, as well as a
directional coupler and resonator arrangement particularly adapted
for borehole acoustic communication. An acoustic communication
system is described especially designed for use in providing
acoustic transmission of information in a borehole. The
communication system comprises a surface transceiver and at least
one downhole transceiver. The surface transceiver operates in
conjunction with a host computer that sends commands to the
downhole transceiver. Subsequently, the downhole transceiver
transmits encoded data from subsurface, borehole sensors to the
surface transceiver. The preferred embodiment uses Minimum Shift
Keying (MSK) modulation for both transmitting commands to the
downhole unit and for transmitting data to the surface transceiver.
To facilitate operation of a coherent communication system in the
inhospitable environment of a borehole, the acoustic channel is
characterized to enable the system to choose the best possible
frequency and bandwidth for communication transmission.
Additionally, the system achieves synchronous operation by
transmitting synchronization signals between the downhole
transceiver and the surface transceiver prior to the units
exchanging commands and data.
Inventors: |
Rorden; Louis H. (Los Altos,
CA), Patel; Ashok (San Jose, CA), Leggett, III; James
V. (Houston, TX), Gibbons; Frank L. (Houston, TX),
Owens; Steven C. (Katy, TX) |
Assignee: |
Baker Hughes Incorporated
(Houston, TX)
|
[*] Notice: |
The portion of the term of this patent
subsequent to June 14, 2011 has been disclaimed. |
Family
ID: |
39092888 |
Appl.
No.: |
08/108,958 |
Filed: |
August 18, 1993 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
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715364 |
Jun 14, 1991 |
5283768 |
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Current U.S.
Class: |
367/83;
340/854.3; 340/854.4 |
Current CPC
Class: |
E21B
47/16 (20130101); G08C 23/00 (20130101); G08C
23/02 (20130101); E21B 47/24 (20200501); E21B
47/107 (20200501); E21B 47/18 (20130101); E21B
47/20 (20200501); Y10S 367/912 (20130101); G08C
2201/51 (20130101) |
Current International
Class: |
E21B
47/16 (20060101); G08C 23/02 (20060101); G08C
23/00 (20060101); E21B 47/18 (20060101); E21B
47/12 (20060101); E21B 47/10 (20060101); G01V
001/40 () |
Field of
Search: |
;367/83,912,82
;340/854.3,854.4 ;73/151,152,155 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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0377378 |
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EP |
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2142453 |
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1540479 |
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1592995 |
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2123458 |
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2015307 |
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0000 |
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Primary Examiner: Lobo; Ian J.
Attorney, Agent or Firm: Hunn; Melvin A.
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATION
The present application is a C-I-P of U.S. Pat. No. 5,283,768 Ser.
No. 07/715,364, entitled "Borehole Liquid Acoustic Wave
Transducer", filed Jun. 14, 1991 and assigned to the assignee
herein, and incorporated by reference herein.
Claims
What is claimed is:
1. An acoustic communication apparatus for use in a wellbore having
a plurality of concentrically nested tubular strings disposed
therein, with at least one fluid column defined therein selected as
a communication channel, comprising:
a transducer in force-transferring communication with said
communication channel;
a housing for securing said transducer in a selected location
within said wellbore, said housing affecting an acoustic admittance
of said communication channel; and
at least one impedance matching member, dimensioned in (1),
cross-sectional area and (2) length with respect to at least one of
(1) said communication channel, (2) said housing, and (3) at least
one probable acoustic communication frequency to minimize
reflection of acoustic energy at said housing.
2. An acoustic communication apparatus according to claim 1,
wherein said at least one impedance matching member is located
proximate said housing.
3. An acoustic communication apparatus according to claim 1,
wherein said at least one impedance matching member is located
intermediate said housing and a remotely-located communication
node.
4. An acoustic communication apparatus according to claim 1:
wherein said communication channel comprises an annular region
defined by said concentrically nested tubular strings;
wherein said housing extends into, and partially obstructs, said
annular region, thereby affecting acoustic admittance of said
communication channel; and
wherein said at least one impedance matching member is sized to
also partially obstruct said annular region, but to a lesser extent
than said housing.
5. An acoustic communication apparatus according to claim 4:
wherein said at least one impedance matching member is radially
dimensioned to provide a surrounding unobstructed annular region
which has a predetermined cross-sectional area.
6. An acoustic communication apparatus according to claim 5:
wherein said predetermined cross-sectional area comprises a
geometric average of the mathematical product of (a) the
cross-sectional area of an unobstructed portion of said annular
region and (b) the cross-sectional area of said annular region
surrounding said housing.
7. An acoustic communication apparatus according to claim 4:
wherein said at least one impedance matching member has a length
which is approximately equal to one-quarter wavelength of said at
least one probable acoustic communication frequency.
8. An acoustic communication apparatus for use in a wellbore having
a plurality of concentrically nested tubular strings disposed
therein, with at least one fluid column defined therein selected as
a communication channel which extends between a first communication
node and a second communication node, comprising:
a transducer, located at said first communication node, in
force-transferring communication with said communication
channel;
a housing for securing said transducer to a selected one of said
concentrically nested tubular strings, with said housing extending
into, and partially obstructing, said annular region;
a reflection member positioned relative to said housing so that
said transducer is intermediate (a) said communication channel and
(b) said reflection member; and
said reflection member being dimensioned in (1) cross-sectional
area, and (2) length with respect to at least one of (1) said
communication channel, (2) said housing, and (3) a probable
acoustic communication frequency to reflect acoustic energy into
said communication channel between said first and second
communication nodes.
9. An acoustic communication apparatus according to claim 8:
wherein said reflection member extends into, and partially
obstructs, said annular region, but to a lesser extent than said
housing.
10. An acoustic communication apparatus according to claim 8:
wherein said reflection member partially obstructs said annular
region to provide a surrounding annular region with a
cross-sectional area approximately equal to the cross-sectional
area of said communication channel.
11. An acoustic communication apparatus according to claim 8:
wherein said reflection member is spaced from said housing a
distance approximately equal to one-quarter wavelength of said
probable acoustic communication frequency; and
wherein said reflection member has a length approximately equal to
one-quarter wavelength of said probable acoustic communication
frequency.
12. An acoustic communication apparatus according to claim 11:
wherein said reflection member defines:
(a) a multiple number of step increases in cross-sectional area in
said wellbore, spaced from said transducer generally an odd number
of quarter wavelengths about said probable acoustic communication
frequency, said step increases being positioned lengthwise in said
wellbore in a direction from said transducer opposite that of
desired communication; and
(b) a multiple number of step decreases in the liquid
cross-sectional area in said wellbore, interleaved with said step
increases, and spaced from said transducer generally an even number
of quarter wavelengths of said probable acoustic communication
frequency.
13. An acoustic communication apparatus for use in a wellbore
having a plurality of concentrically nested tubular strings
disposed therein, with a selected fluid column therein selected as
a communication channel for acoustic communication between a first
communication node and a second communication node, comprising:
an actuator member for selected bidirectional conversion of (a) a
provided coded electrical signal to a corresponding generated coded
acoustic signal during a message transmission mode of operation,
and (b) a provided coded acoustic signal to a corresponding
generated coded electrical signal during a message reception mode
of operation; and
a housing for securing said actuator member in a selected location
within said wellbore, said housing extending into, and partially
obstructing, said annular region, so that said annular region
surrounding said housing has a cross-sectional area which is less
than that of said communication channel.
14. An acoustic communication apparatus according to claim 13,
further comprising:
an impedance matching member for minimizing reflection of acoustic
energy at said housing.
15. An acoustic communication apparatus according to claim 13,
further comprising:
a reflection member for reflecting acoustic energy into said
communication channel.
16. An acoustic communication apparatus according to claim 13,
further comprising:
a fluid body located within said housing, and communicating with
said communication channel, for preferentially directing acoustic
energy into said communication channel to reinforce acoustic
communication.
17. In borehole communication, a method of communicating data
between two locations using travel of acoustic waves in a borehole
liquid without modifying or requiring liquid flow, comprising the
steps of:
(a) characterizing an acoustic channel created by said liquid in
said borehole by:
(1) generating a characterizing signal at one of said
locations;
(2) transmitting said characterizing signal via said borehole
liquid to the other of said locations; and
(3) analyzing said characterizing signal after it is received at
said second location to select a frequency band having a channel
capacity adequate for the desired communication;
(b) generating an acoustic signal having a frequency in said
frequency band, which signal defines said data;
(c) coupling said acoustic signal to a borehole liquid in a first
portion thereof positioned at a first one of said locations;
(d) receiving said acoustic signal from a second portion of said
borehole liquid at the second one of said locations; and
thereafter
(e) recovering said data from said acoustic signal.
18. The method of claim 17 wherein at least a part of said
communication is within a borehole within which an annulus is
defined for borehole liquid, and at least one of said portions is
within said annulus.
19. The method of claim 17 wherein said acoustic signal is a signal
which is modulated with said data.
20. The method of claim 17 further including the steps of:
(f) generating a second acoustic signal having a frequency in said
frequency band, which second signal defines data;
(g) coupling said second acoustic signal to said borehole liquid in
said second portion thereof positioned at said second one of said
locations;
(h) receiving said second acoustic signal from said second portion
of said borehole liquid at the first one of said locations; and
thereafter
(i) recovering said data from said second acoustic signal.
21. The method of claim 17 wherein said analyzing step includes
performing a fast Fourier transform upon said characterizing
signal.
22. The method of claim 17 wherein said analyzing step
includes:
determining a signal to noise ratio for said characterizing signal
within a specified frequency band;
determining a bandwidth of constant signal to noise ratio within
said specified frequency band; and
choosing a frequency within said specified frequency band having a
best signal to noise ratio and an acceptable bandwidth therearound
as said best transmission frequency.
23. In borehole communication, a method of communicating data
between two locations using travel of acoustic waves in a
transmission medium extending in said borehole, comprising the
steps of:
(a) generating a first synchronizing signal in a first transceiver
at one of said locations;
(b) acoustically transmitting said first synchronizing signal via
said transmission medium to a second transceiver at the other of
said locations;
(c) receiving said synchronizing signal at said second
transceiver;
(d) synchronizing said second transceiver with said first
transceiver based upon the received synchronizing signal;
(e) generating a second synchronizing signal in said second
transceiver;
(f) acoustically transmitting said second synchronizing signal via
said transmission medium to said second transceiver;
(g) receiving said second synchronizing signal at said second
transceiver; and
(h) synchronizing said first transceiver with said second
transceiver based upon the received second synchronizing
signal.
24. The method of claim 23 wherein said first synchronizing signal
is a chirp signal.
25. The method of claim 23 wherein said second synchronizing signal
is comprised of two tones.
26. The method of claim 25 further including the steps of:
(i) performing a fast Fourier transform on each tone;
(j) determining a phase difference between each fast Fourier
transform of each tone;
(k) generating a time adjustment from said phase difference;
and
(l) adjusting a clock of said first transceiver by said time
adjustment.
27. In borehole communication, a method of communicating data
between two locations using travel of acoustic waves in a borehole
liquid for such communication, comprising the steps of:
(a) synchronizing a first transceiver at one of said locations with
a second transceiver at the other of said locations by:
(1) generating a synchronizing signal in said first
transceiver;
(2) acoustically transmitting said synchronizing signal via said
borehole liquid to said second transceiver;
(3) receiving said synchronizing signal at said second
transceiver;
(4) approximately synchronizing said second transceiver with said
first transceiver based upon the received synchronizing signal;
(5) generating a second synchronizing signal in said second
transceiver;
(6) acoustically transmitting said second synchronizing signal via
said borehole liquid to said second transceiver;
(7) receiving said second synchronizing signal at said second
transceiver;
(8) synchronizing said first transceiver with said second
transceiver based upon the received second synchronizing
signal;
(b) modulating a first electrical signal with a data signal for
said first transceiver;
(c) generating a modulated acoustic signal from said first
electrical signal after the latter is modulated;
(d) coupling said modulated acoustic signal with said first
transceiver to a first portion of borehole liquid located at said
first transceiver;
(e) thereafter receiving said modulated acoustic signal with said
second transceiver from a second portion of said borehole
liquid;
(f) converting said received modulated acoustic signal to a second
electrical signal defining said data; and
(g) recovering said data from said second electrical signal.
28. The method of claim 27 wherein said first synchronizing signal
is a chirp signal.
29. The method of claim 27 wherein said second synchronizing signal
is comprised of two tones.
30. The method of claim 29 wherein said step of receiving said
second synchronizing signal includes:
performing a fast Fourier transform on each tone;
determining a phase difference between each fast Fourier transform
of each tone;
generating a time adjustment from said phase difference; and
adjusting a clock of said first transceiver by said time
adjustment.
31. In borehole communication, a method of communicating data
between two locations using travel of acoustic waves in a
transmission medium extending in said borehole without the
transmission medium itself having to travel between such locations
for such communication, comprising the steps of:
(a) characterizing an acoustic channel created by said transmission
medium by:
(1) generating a characterizing signal at a first one of said
locations;
(2) acoustically transmitting said characterizing signal via said
transmission medium to a second one of said locations;
(3) receiving said characterizing signal at said second
location;
(4) analyzing said received characterizing signal;
(5) determining a best transmission frequency for communicating
from one of said first locations to the other based upon said
analyzed signal;
(b) synchronizing a first transceiver at one of said locations with
a second transceiver at the other of said locations;
(c) modulating a first electrical signal with a data signal for
said first transceiver;
(d) generating a modulated acoustic signal from said first
electrical signal after the latter is modulated;
(e) coupling said modulated acoustic signal with said first
transceiver to a first portion of said transmission medium located
at said first transceiver;
(f) thereafter receiving said modulated acoustic signal with said
second transceiver from a second portion of said transmission
medium;
(g) converting said received modulated acoustic signal to a second
electrical signal defining said data; and
(h) recovering said data from said second electrical signal.
32. The method of claim 31 wherein said step of receiving said
characterizing signal includes performing a fast Fourier transform
upon said characterizing signal.
33. The method of claim 31 wherein said characterizing signal is a
chirp signal.
34. The method of claim 31 wherein said step of analyzing said
received characterizing signal includes:
determining a signal to noise ratio for said characterizing signal
within a specified frequency band;
determining a bandwidth of acceptable signal-to-noise ratio within
said specified frequency band;
choosing a center frequency within said bandwidth as said
transmission frequency.
35. A method of bi-directionally communicating information and
control data using acoustic waves between a downhole acoustic
transceiver contained in a downhole carrier incorporated into a
drillstring and a surface acoustic transceiver, said method
comprising the steps of:
(a) generating a characterizing signal in a first transceiver for
characterizing an acoustic channel created by a transmission medium
in said borehole;
(b) acoustically transmitting said characterizing signal via said
transmission medium to a second transceiver;
(c) receiving said characterizing signal with said second
transceiver;
(d) analyzing said received characterizing signal;
(e) determining a best transmission frequency for communicating
from said first transceiver to said second transceiver via
transmission medium;
(f) generating a first synchronizing signal in said first
transceiver;
(g) acoustically transmitting said first synchronizing signal via
said borehole liquid to said second transceiver;
(h) receiving said first synchronizing signal at said second
transceiver;
(i) synchronizing said second transceiver with said first
transceiver based upon the received first synchronizing signal;
(j) generating a second synchronizing signal in said second
transceiver;
(k) acoustically transmitting said second synchronizing signal via
said transmission medium to said second transceiver;
(l) receiving said second synchronizing signal at said second
transceiver;
(m) synchronizing said first transceiver with said second
transceiver based upon the received second synchronizing
signal;
(n) modulating a first electrical signal with a first data signal
within said first transceiver;
(o) generating a first modulated acoustic signal from said first
electrical signal;
(p) coupling said first modulated acoustic signal to said
transmission medium;
(q) receiving said first modulated acoustic signal with said second
transceiver;
(r) converting said received modulated acoustic signal to a second
electrical signal;
(s) recovering said first data signal from said second electrical
signal;
(t) modulating a third electrical signal with a second data signal
within said second transceiver;
(u) generating a second modulated acoustic signal from said third
electrical signal;
(v) coupling said second modulated acoustic signal to said
transmission medium;
(w) receiving said second modulated acoustic signal with said first
transceiver;
(x) converting said received second modulated acoustic signal to a
fourth electrical signal; and
(y) recovering said second data signal from said fourth electrical
signal.
36. The method of claim 30 wherein said first data signal is a
command signal and said second data signal is a sensor signal and a
command acknowledgement signal.
37. The method of claim 30 wherein said transmission medium is
borehole liquid.
38. A method of transmitting data in a wellbore between a first
transceiver at a first communication node and a second transceiver
at a second communication node through a communication channel
defined in a wellbore component, comprising:
generating a characterizing signal at a selected one of said first
and second communication nodes;
said characterizing signal including a plurality of signal
components, each having a selected frequency, with said plurality
of signal components spanning a preselected range of
frequencies;
applying said characterizing signal to said communication
channel;
receiving said characterizing signal with a selected one of said
first and second transceivers;
analyzing said characterizing signal to identify portions of said
preselected range of frequencies which are suitable for
communicating data between said first and second communication
nodes at that particular time; and
communicating data in said communication channel in at least one
selected portion of said preselected range of frequencies.
39. A method of transmitting data according to claim 38, wherein
said wellbore component which defines said communication channel
comprises a fluid column.
40. A method of transmitting data according to claim 38, wherein
said wellbore component which defines said communication channel
comprises a wellbore tubular string.
41. A method of transmitting data according to claim 38, further
comprising:
continuously generating, applying, receiving, and analyzing said
characterizing signal to identify portions of said preselected
range of frequencies which are suitable for communicating data
between said first and second communication nodes at subsequent
times; and
communicating data in said communication channel in at least one
selected portion of said preselected range of frequencies.
42. A method of transmitting data according to claim 38, further
comprising:
during said step of communicating data, automatically and
periodically generating, applying, receiving, and analyzing said
characterizing signal to identify portions of said preselected
range of frequencies which are suitable for communicating data
between said first and second communication nodes; and
switching between selected portions of said preselected range of
frequencies to optimize communication of data between said first
and second communication nodes.
43. A method of transmitting data according to claim 38:
wherein, during said step of generating, said characterizing signal
is generated utilizing a selected one of said first and second
transceivers.
44. A method of transmitting data according to claim 38:
wherein a plurality of characterizing signals are generated at
selected ones of said first and second communication nodes, with
each being analyzed to identify portions of said preselected range
of frequencies which are suitable for communicating data in a
particular direction between said first and second communication
nodes.
45. A method of transmitting data according to claim 38:
wherein said step of analyzing includes identifying at least one
portion of said preselected range of frequencies which have an
adequate bandwidth for communication of data.
46. A method of transmitting data according to claim 38:
wherein said step of analyzing includes identifying at least one
portion of said preselected range of frequencies which have an
adequate signal to noise characteristic for communication of
data.
47. A method of transmitting data according to claim 38:
wherein said step of analyzing includes performing frequency-domain
analysis of the received characterizing signal.
48. A method according to claim 38:
wherein said step of analyzing includes creating a histogram
utilizing preselected frequency bins.
49. A method of transmitting data according to claim 38:
wherein said step of analyzing includes comparison of coherent
running totals to incoherent running totals.
50. A method of transmitting data according to claim 38, further
comprising:
synchronizing operation of said first and second transceivers.
51. A method of transmitting data according to claim 38, further
comprising:
subsequent to said step of analyzing, transmitting data between
said first and second transceivers which identifies at least a
center frequency for at least one selected portion of said
preselected range of frequencies.
52. A method of transmitting data according to claim 38:
wherein said communication channel comprises a dynamic fluid column
in said wellbore; and
wherein said method steps of claim 38 continually performed to
optimize data communication in said dynamic fluid column.
53. A method of transmitting data according to claim 38:
wherein said communication channel comprises a dynamic fluid column
in said wellbore;
wherein mechanical changes affect acoustic transmission properties
of said communication channel; and
wherein said steps of claim 38 are performed to automatically
optimize data communication in said dynamic fluid column,
notwithstanding said mechanical changes.
54. An acoustic communication apparatus for use in a wellbore with
a selected fluid column therein selected as a communication channel
for acoustic communication between a first communication node and a
second communication node, comprising:
a first actuator member for conversion of at least one of (a) a
provided coded electrical signal to a corresponding generated coded
acoustic signal during a message transmission mode of operation,
and (b) a provided coded acoustic signal to a corresponding
generated coded electrical signal during a message reception mode
of operation;
a second actuator member for conversion of at least one of at least
one of (a) a provided coded electrical signal to a corresponding
generated coded acoustic signal during a message transmission mode
of operation, and (b) a provided coded acoustic signal to a
corresponding generated coded electrical signal during a message
reception mode of operation;
housings for securing said first and second actuator members in
selected locations within said wellbore; and
wherein said acoustic communication apparatus is operable in a
plurality of modes of operation including at least:
(a) a communication channel characterization mode of operation
wherein a characterization signal is transmitted in said
communication channel and then analyzed to identify at least one
communication frequency for optimal communication; and
(b) a data communication mode of operation, wherein data is
transmitted between said first and second communication nodes
through operation of said first and second actuator members at said
at least one communication frequency.
55. An acoustic communication apparatus according to claim 54:
wherein said acoustic communication apparatus is utilized to
communicate data within said wellbore during drilling
operations.
56. An acoustic communication apparatus according to claim 54:
wherein said acoustic communication apparatus is utilized to
communicate data in said wellbore during completion operations.
57. An acoustic communication apparatus according to claim 54:
wherein said acoustic communication apparatus is utilized to
communicate data in said wellbore during production operations.
58. An acoustic communication apparatus for use during drilling
operations in a wellbore having a drillstring disposed therein
composed of a drill pipe section and a drill collar section, with a
selected fluid column within said wellbore selected as a
communication channel for acoustic communication between a first
communication node and a second communication node, comprising:
a first actuator member located at said first communication node
for conversion of at least one of (a) a provided coded electrical
signal to a corresponding generated coded acoustic signal during a
message transmission mode of operation, and (b) a provided coded
acoustic signal to a corresponding generated coded electrical
signal during a message reception mode of operation;
a second actuator member located at said second communication node
for conversion of at least one of at least one of (a) a provided
coded electrical signal to a corresponding generated coded acoustic
signal during a message transmission mode of operation, and (b) a
provided coded acoustic signal to a corresponding generated coded
electrical signal during a message reception mode of operation;
housings for securing said first and second actuator members in
selected locations within said wellbore; and
wherein said acoustic communication apparatus is operable in a
plurality of modes of operation including at least:
(a) a communication channel characterization mode of operation
wherein a characterization signal is transmitted in said
communication channel and then analyzed to identify at least one
communication frequency for optimal communication; and
(b) a data communication mode of operation, wherein data is
transmitted between said first and second communication nodes
through operation of said first and second actuator members at said
at least one communication frequency.
59. An acoustic communication apparatus according to claim 58:
wherein said first communication node is located in said drill
collar section of said drillstring;
wherein said second communication node is located in said
drillstring upward from said first communication node;
wherein said first actuator member is utilized to transmit data
pertaining to at least one of (a) drillstring operations, (b)
wellbore conditions, and (c) formation conditions to said second
actuator member.
60. An acoustic communication apparatus according to claim 59:
wherein said data received by said second actuator member is
supplied to a measurement-while-drilling data transmission system
for at least one of (a) processing and (b) retransmission.
61. An acoustic communication apparatus according to claim 59:
wherein said second communication node is located at a wellhead for
said wellbore; and
wherein said first actuator member is utilized to transmit data to
said wellhead.
62. An acoustic communication apparatus according to claim 61:
wherein said first actuator member is utilized to transmit data to
said wellhead in parallel with a measurement-while-drilling data
transmission system.
63. An acoustic communication apparatus according to claim 58:
wherein said first communication node is located in said drill
collar section of said drillstring adjacent a drill bit;
wherein said second communication node is located in said drill
collar section of said drillstring above said first communication
node, adjacent a measurement-while-drilling data transmission
system; and
wherein data pertaining to near-drillbit conditions is transmitted
from said first communication node to said second communication
node.
64. A method of detecting influx of gas into a fluid column in a
wellbore therein which defines a communication channel,
comprising:
providing at least one actuator for conversion of at least one of
(a) a provided coded electrical signal to a corresponding generated
coded acoustic signal during a message transmission mode of
operation, and (b) a provided coded acoustic signal to a
corresponding generated coded electrical signal during a message
reception mode of operation;
utilizing said at least one actuator for generating an
interrogating signal at a selected location within said
wellbore;
applying said interrogating signal to said communication
channel;
receiving said interrogating signal with said at least one
actuator;
analyzing said interrogating signal to identify at least one
of:
(a) portions of a preselected range of frequencies which are
suitable for communicating data in said wellbore at that particular
time;
(b) communication channel attributes; and
(c) signal attributes;
repeating said steps of utilizing, applying, receiving, and
analyzing to identify changes in at least one of:
(a) portions of said preselected range of frequencies which are
suitable for communicating data in said wellbore;
(b) communication channel attributes; and
(c) signal attributes;
which, correspond to a likely influx of gas into said fluid column
in said wellbore.
65. A method according to claim 64:
wherein said portions of said preselected range of frequencies
which are suitable for communicating data in said wellbore are
identified by at least one of (a) frequency, (b) bandwidth, (c) a
signal-to-noise characteristic, (d) signal amplitude, and (e)
signal time delay.
66. A method according to claim 64:
wherein said communication channel attributes include at least one
of:
(a) communication channel length; and
(b) communication channel impedance.
67. A method according to claim 64:
wherein said signal attributes include at least one of:
(a) signal amplitude;
(b) signal phase;
(c) loss of signal in the selected portion of the preselected range
of frequencies of the communication channel; and
(d) signal time delay.
68. A method according to claim 64:
wherein said at least one actuator comprises a single actuator;
and
wherein said interrogating signal received by said single actuator
is an echo signal in said communication channel.
69. A method according to claim 64:
wherein said at least one actuator comprises a first actuator
disposed at a first wellbore location and a second actuator
disposed at a second wellbore location; and
wherein said interrogating signal is transmitted between said first
and second actuators.
70. A method according to claim 64, further comprising:
providing a reflection marker and coupling it to a wellbore
tubular; and
reflecting said interrogating signal off of said reflection
marker.
71. An acoustic communication apparatus for use in a wellbore with
a selected wellbore component therein selected as a communication
channel for acoustic communication between a first communication
node and a second communication node, comprising:
a first actuator member for conversion of at least one of (a) a
provided coded electrical signal to a corresponding generated coded
acoustic signal during a message transmission mode of operation,
and (b) a provided coded acoustic signal to a corresponding
generated coded electrical signal during a message reception mode
of operation;
a second actuator member for conversion of at least one of at least
one of (a) a provided coded electrical signal to a corresponding
generated coded acoustic signal during a message transmission mode
of operation, and (b) a provided coded acoustic signal to a
corresponding generated coded electrical signal during a message
reception mode of operation;
housings for securing said first and second actuator members in
selected locations within said wellbore; and
wherein during a data communication mode of operation:
(a) a binary "one" is transmitted through said communication
channel by utilizing a selected one of said first and second
actuator members to generate an acoustic signal with a plurality of
signal components, said signal components spanning a first
preselected range of frequencies; and
(b) a binary "zero" is transmitted through said communication
channel by utilizing a selected one of said first and second
actuator members to generate an acoustic signal with a plurality of
signal components, said signal components spanning a second
preselected range of frequencies, different from that range of
frequencies for said binary "one".
72. An acoustic communication apparatus according to claim 71:
wherein said communication channel comprises a fluid column defined
within said borehole.
73. An acoustic communication apparatus according to claim 71
wherein, during said data communication mode of operation:
(a) said binary "one" is detected by a selected one of said first
and second actuator members by examining energy levels within said
first preselected range of frequencies; and
(b) said binary "zero" is detected by a selected one of said first
and second actuator members by examining energy levels with said
second preselected range of frequencies.
74. An acoustic communication apparatus according to claim 73:
wherein said energy levels for said first preselected range of
frequencies is compared to a baseline energy level for said first
preselected range of frequencies; and
wherein said energy levels for said second preselected range of
frequencies is compared to a baseline energy level for said second
preselected range of frequencies.
75. A method of detecting at least one of (a) a fluid influx and
(b) a gas influx into a fluid column in a wellbore therein which
defines a communication channel, comprising:
providing at least one actuator for conversion of at least one of
(a) a provided coded electrical signal to a corresponding generated
coded acoustic signal during a message transmission mode of
operation, and (b) a provided coded acoustic signal to a
corresponding generated coded electrical signal during a message
reception mode of operation;
utilizing said at least one actuator for generating an
interrogating signal at a selected location within said
wellbore;
applying said interrogating signal to said communication
channel;
receiving said interrogating signal with said at least one
actuator;
analyzing said interrogating signal to identify at least one
of:
(a) portions of a preselected range of frequencies which are
suitable for communicating data in said wellbore at that particular
time;
(b) communication channel attributes; and
(c) signal attributes;
repeating said steps of utilizing, applying, receiving, and
analyzing to identify changes in at least one of:
(a) portions of said preselected range of frequencies which are
suitable for communicating data in said wellbore;
(b) communication channel attributes; and
(c) signal attributes;
which, correspond to a likely occurrence of at least one of (a)
fluid influx and (b) gas influx into said fluid column in said
wellbore.
76. A method according to claim 75:
wherein said portions of said preselected range of frequencies
which are suitable for communicating data in said wellbore are
identified by at least one of (a) frequency, (b) band width, (c) a
signal-to-noise characteristic, (d) signal amplitude, and (e)
signal time delay.
77. A method according to claim 75:
wherein said communication channel attributes include at least one
of:
(a) communication channel length;
(b) communication channel impedance;
(c) frequency band width; and
(d) phase shift.
78. A method according to claim 75:
wherein said signal attributes include at least one of:
(a) signal amplitude;
(b) signal phase;
(c) loss of signal;
(d) signal time delay;
(e) frequency response; and
(f) acoustic spectral density.
79. A method according to claim 75:
wherein said at least one actuator comprises a single actuator;
and
wherein said interrogating signal received by said single actuator
is an echo signal in said communication channel.
80. A method according to claim 75:
wherein said at least one actuator comprises a first actuator
disposed at a first wellbore location and a second actuator
disposed at a second wellbore location; and
wherein said interrogating signal is transmitted between said first
and second actuators.
81. A method according to claim 75, further comprising:
providing a reflection marker and coupling it to a wellbore
tubular; and
reflecting said interrogating signal off of said reflection
marker.
82. A method of detecting at least one of (a) fluid influx, and (b)
gas influx into a fluid column in a wellbore therein which defines
a communication channel, comprising:
providing at least one actuator for conversion of at least one of
(a) a provided coded electrical signal to a corresponding generated
coded acoustic signal during a message transmission mode of
operation, and (b) a provided coded acoustic signal to a
corresponding generated coded electrical signal during a message
reception mode of operation;
utilizing said at least one actuator for generating an
interrogating signal at a selected location within said
wellbore;
applying said interrogating signal to said communication
channel;
receiving said interrogating signal with said at least one
actuator;
analyzing said interrogating signal to identify at least one
of:
(a) portions of a preselected range of frequencies which are
suitable for communicating data in said wellbore at that particular
time;
(b) communication channel attributes; and
(c) signal attributes;
repeating said steps of utilizing, applying, receiving, and
analyzing to identify changes in at least one of:
(a) portions of said preselected range of frequencies which are
suitable for communicating data in said wellbore;
(b) communication channel attributes; and
(c) signal attributes;
which, correspond to at least one of a likely (a) fluid influx, and
(b) gas influx, into said fluid column in said wellbore; and
displaying information which is sufficient to allow a human
operator to detect and monitor at least one of a likely (a) fluid
influx, and (b) gas influx.
83. A method according to claim 82:
wherein said portions of said preselected range of frequencies
which are suitable for communicating data in said wellbore are
identified by at least one of (a) frequency, (b) band width, (c) a
signal-to-noise characteristic, (d) signal amplitude, and (e)
signal time delay.
84. A method according to claim 82 wherein during said step of
displaying, at least one of the following communication channel
attributes is displayed:
(a) communication channel length;
(b) communication channel impedance;
(c) frequency band width; and
(d) phase shift.
85. A method according to claim 82 wherein during said step of
displaying, at least one of the following signal attributes is
displayed:
(a) signal amplitude;
(b) signal phase;
(c) loss of signal;
(d) signal time delay;
(e) frequency response; and
(f) acoustic spectral density.
86. A method according to claim 82:
wherein said at least one actuator comprises a single actuator;
and
wherein said interrogating signal received by said single actuator
is an echo signal in said communication channel.
87. A method according to claim 82:
wherein said at least one actuator comprises a first actuator
disposed at a first wellbore location and a second actuator
disposed at a second wellbore location; and
wherein said interrogating signal is transmitted between said first
and second actuators.
88. A method according to claim 82, further comprising:
providing a reflection marker and coupling it to a wellbore
tubular; and
reflecting said interrogating signal off of said reflection marker.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
The present invention relates to:
(a) a transducer which may be utilized to transmit and receive data
in a wellbore;
(b) a communication system for improving the communication of data
in a wellbore;
(c) one application of the transducer in a
measurement-while-drilling system; and
(4) one application of the transducer and communication system to
detect gas influx in a wellbore.
2. Background of the Invention
One of the more difficult problems associated with any borehole is
to communicate intelligence between one or more locations down a
borehole and the surface, or between downhole locations themselves.
For example, communication is desired by the oil industry to
retrieve, at the surface, data generated downhole during drilling
operations, including during quiescent periods interspersing actual
drilling procedures or while tripping; during completion operations
such as perforating, fracturing, and drill stem or well testing;
and during production operations such as reservoir evaluation
testing, pressure and temperature monitoring. Communication is also
desired in such industry to transmit intelligence from the surface
to downhole tools or instruments to effect, control or modify
operations or parameters.
Accurate and reliable downhole communication is particularly
important when data (intelligence) is to be communicated. This
intelligence often is in the form of an encoded digital signal.
One approach has been widely considered for borehole communication
is to use a direct wire connection between the surface and the
downhole location(s). Communication then can be via electrical
signal through the wire. While much effort has been expended toward
"wireline" communication, this approach has not been adopted
commercially because it has been found to be quite costly and
unreliable. For example, one difficulty with this approach is that
since the wire is often laid via numerous lengths of a drill stem
or production tubing, it is not unusual for there to be a break or
a poor wire connection which arises at the time the wire assembly
is first installed. While it has been proposed (see U.S. Pat. No.
4,215,426) to avoid the problems associated with direct electrical
coupling of drill stems by providing inductive coupling for the
communication link at such location, inductive coupling has as a
problem, among others, major signal loss at every coupling. It also
relies on installation of special and complex drillstring
arrangements.
Another borehole communication technique that has been explored is
the transmission of acoustic waves. Such physical waves need a
transmission medium that will propagate the same. It will be
recognized that matters such as variations in earth strata, density
make-up, etc., render the earth completely inappropriate for an
acoustic communication transmission medium. Because of these known
problems, those in the art generally have confined themselves to
exploring acoustic communication through borehole related
media.
Much effort has been expended toward developing an appropriate
acoustic communication system in which the borehole drill stem or
production tubing itself acts as the transmission medium. A major
problem associated with such arrangements is caused by the fact
that the configurations of drill stems or production tubing
generally vary significantly lengthwise. These variations typically
are different in each hole. Moreover, a configuration in a
particular borehole may vary over time because, for example, of the
addition of tubing and tools to the string. The result is that
there is no general usage system relying on drill stem or
production tubing transmission that has gained meaningful market
acceptance.
Efforts have also been made to utilize liquid within a borehole as
the acoustic transmission medium. At first blush, one would think
that use of a liquid as the transmission medium in a borehole would
be relatively simple approach, in view of the wide usage and
significant developments that have been made for communication and
sonar systems relying on acoustic transmission within the
ocean.
Acoustic transmission via a liquid within a borehole is
considerably different than acoustic transmission within an open
ocean because of the problems associated with the boundaries
between the liquid and its confining structures in a borehole.
Criteria relating to these problems are of paramount importance.
However, because of the attractiveness of the concept of acoustic
transmission in a liquid independent of movement thereof, a system
was proposed in U.S. Pat. No. 3,964,556 utilizing pressure changes
in a non-moving liquid to communicate. Such system has not been
found practical, however, since it is not a self-contained system
and some movement of the liquid has been found necessary to
transmit pressure changes.
In light of the above, meaningful communication of intelligence via
borehole liquids has been limited to systems which rely on flow of
the liquid to carry on acoustic modulation from a transmission
point to a receiver. This approach is generally referred to in the
art as MWD (measure while drilling). Developments relating to it
have been limited to communication during the drilling phase in the
life of a borehole, principally since it is only during drilling
that one can be assured of fluid which can be modulated flowing
between the drilling location and the surface. Most MWD systems are
also constrained because of the drilling operation itself. For
example, it is not unusual that the drilling operation must be
stopped during communication to avoid the noise associated with
such drilling. Moreover, communication during tripping is
impossible.
In spite of the problems with MWD communication, much research has
been done on the same in view of the desirability of good borehole
communication. The result has been an extensive number of patents
relating to MWD, many of which are directed to proposed solutions
to the various problems that have been encountered. U.S. Pat. No.
4,215,426 describes an arrangement in which power (rather than
communication) is transmitted downhole through fluid modulation
akin to MWD communication, a portion of which power is drained off
at various locations downhole to power repeaters in a wireline
communication transmission system.
The development of communication using acoustic waves propagating
through non-flowing fluids in a borehole has been impeded by lack
of a suitable transducer. To be practical for a borehole
application, such a transducer has to fit in a pressure barrel with
an outer diameter of no more than 1.25 inches, operate at
temperatures up to 150.degree. C. and pressures up to 1000 bar, and
survive the working environment of handling and running in a well.
Such a transducer would also have to take into consideration the
significant differences between communication in a non-constrained
fluid environment, such as the ocean, and a confined fluid
arrangement, such as in a borehole.
The development of reliable communication using acoustic waves
propagating through non-flowing fluids in a borehole has been
impeded by the fact that the borehole environment is extremely
noisy. Moreover, to be practical, an acoustic communication system
using non-flowing liquid is required to be highly adaptive to
variations in the borehole channel and must provide robust and
reliable throughput of data in spite of such variations.
SUMMARY OF THE INVENTION
THE TRANSDUCER:
The present invention relates to a practical borehole acoustic
communication transducer. It is capable of generating, or
responding to, acoustic waves in a viscous liquid confined in a
borehole. Its design takes into consideration the waveguide nature
of a borehole. It has been found that, to be practical, a borehole
acoustic transducer has to generate, or respond to, acoustic waves
at frequencies below one kilohertz with bandwidths of tens of
Hertz, efficiently in various liquids. It has to be able to do so
while providing high displacement and having a lower mechanical
impedance than conventional open ocean devices. The transducer of
the invention meets these criteria as well as the size and
operating criteria mentioned above.
The transducer of the invention has many features that contribute
to its capability. It is similar to a moving coil loudspeaker in
that movement of an electric winding relative to magnetic flux in
the gap of a magnetic circuit is used to convert between electric
power and mechanical motion. It uses the same interaction for
transmitting and receiving. A dominant feature of the transducer of
the invention is that a plurality of gaps are used with a
corresponding number (and placement) of electrical windings. This
facilitates developing, with such a small diameter arrangement, the
forces and displacements found to be necessary to transduce the low
frequency waves required for adequate transmission through
non-flowing viscous fluid confined in a borehole. Moreover, a
resonator may be included as part of the transducer if desired to
provide a compliant backload.
The invention includes several arrangements responsible for
assuring that there is good borehole transmission of acoustic
waves. For one, a transition section is included to provide
acoustic impedance matching in the borehole liquid between sections
of the borehole having significantly different cross-sectional
areas such as between the section of the borehole having the
transducer and any adjacent borehole section. Reference throughout
this patent specification to a "cross-sectional" area is reference
to the cross-sectional area of the transmission (communication
channel.) For another, a directional coupler arrangement is
described which is at least partially responsible for inhibiting
transmission opposite to the direction in the borehole of the
desired communication. Specifically, a reflection section is
defined in the borehole, which section is spaced generally an odd
number of quarter wavelengths from the transducer and positioned in
a direction opposite that desired for the communication, to reflect
back in the proper communication direction, any acoustic waves
received by the same which are being propagated in the wrong
direction. Most desirably, a multiple number of reflection sections
meeting this criteria are provided as will be described in
detail.
A special bidirectional coupler based on back-loading of the
transducer piston also can be provided for this purpose. Most
desirably, the borehole acoustic communication transducer of the
invention has a chamber defining a compliant back-load for the
piston, through which a window extends that is spaced from the
location at which the remainder of the transducer interacts with
borehole liquid by generally an odd number of quarter wavelengths
of the nominal frequency of the central wavelength of potential
communication waves at the locations of said window and the point
of interaction.
Other features and advantages of the invention will be disclosed or
will become apparent from the following more detailed description.
While such description includes many variations which occurred to
Applicant, it will be recognized that the coverage afforded
Applicant is not limited to such variations. In other words, the
presentation is supposed to be exemplary, rather than
exhaustive.
THE COMMUNICATION SYSTEM:
The present invention relates to a practical borehole acoustic
communication system. It is capable of communicating in both
flowing and non-flowing viscous liquids confined in a borehole,
although many of its features are useful in borehole communication
with production tubing or a drill stem being the acoustic medium.
Its design, however, takes into consideration the waveguide nature
of a borehole. It has been found that to be practical a borehole
acoustic communication system has to operate at frequencies below
one kilohertz with an adequate bandwidth. The bandwidth depends on
various factors, including the efficiency of the transmission
medium. It has been found that a bandwidth of at least several
Hertz are required for efficient communication in various liquids.
The system must transfer information in a robust and reliable
manner, even during periods of excessive acoustic noise and in a
dynamic environment.
As an important feature of the invention, the acoustic
communication system characterizes the transmission channel when
(1) system operation is initiated and (2) when synchronization
between the downhole acoustic transceiver (DAT) and the surface
acoustic transceiver (SAT) is lost. To facilitate the channel
characterization, a wide-band "chirp" signal, (a signal having its
energy distributed throughout the candidate spectrum) is
transmitted from the DAT to the SAT. The received signal is
processed to determine the portion of the spectrum that provides an
exceptional signal to noise ratio and a bandwidth capable of
supporting data transmission.
As another important feature of the invention, it provides two-way
communication between the locations. Each of the communication
transducers is a transceiver for both receiving acoustic signals
from, and for imparting acoustic signals to, the (preferably)
non-moving borehole liquid. The communication is reciprocal in that
it is provided by assuring that the electrical load impedance for
receiving an acoustic signal from the borehole liquid equals the
source impedance of such transceiver for transmitting. Most
desirably, the transceivers are time synchronized to provide a
robust communication system. Initial synchronization is
accomplished through transmission of a synchronization signal in
the form of a repetitive chirp sequence by one of the units, such
as the downhole acoustic transceiver (DAT) in the preferred
embodiment. The surface acoustic transceiver (SAT) processes the
received sequence to establish approximate clock synchronization.
When communication is between a downhole location and the surface,
as in the preferred embodiment, it is preferred that most, if not
all, of the data processing take place at the surface where space
is plentiful.
This first synchronization is only an approximation. As another
dominant feature, a second synchronization signal is transmitted
from the SAT to the DAT to refine such synchronization. The second
synchronization signal is comprised of two tones, each of a
different frequency. Signal analysis of these tones by the DAT
enables the timing of the DAT to be adjusted into synchrony with
the SAT.
Although the communication system of the invention is particularly
designed for use of a borehole liquid as the transmission medium,
many of its features are usable to improve acoustic transmission
when the transmission system utilizes a drill stem, production
tubing or other means extending in a borehole as a transmission
medium. For example, it provides clock correction during the time
data is being transmitted. Other features and advantages of the
invention either will become apparent or will be described in the
following more detailed description of a preferred embodiment and
alternatives.
THE MEASUREMENT-WHILE-DRILLING APPLICATION:
While the preferred embodiment of the present invention discussed
herein is the utilization of the communication system in a
producing oil and gas well, it is also possible to utilize the
transducer and the communication system of the present invention
during drilling operations to transmit data, preferably through the
drilling fluid, between (1) selected points in the drillstring, or
(2) between a selected point in the drillstring and the earth's
surface. The present invention can be utilized in parallel with a
conventional measurement-while-drilling data transmission system,
or as a substitute for a conventional measurement-while-drilling
data transmission system. The present invention is superior to
conventional measurement-while-drilling data transmission systems
insofar as communication can occur while there is no circulation of
fluid in the wellbore. The present invention can be utilized for
the bidirectional transmission of data and remote control signals
within the wellbore.
GAS INFLUX DETECTION:
The transducer and communication system of the present invention
can also be utilized in a wellbore to detect the entry of natural
gas into the wellbore, typically during drilling and completion
operations. As those skilled in the art will understand, the
introduction of high pressure gas into a fluid column in the
wellbore can result in loss of control over the well, and in the
worst case, can result in a blowout of the well. Present
technologies are inadequate for determining both (1) that a
undesirable gas influx has occurred, and (2) the location of the
gas "bubble" within the fluid column (bear in mind the gas influx
will travel generally upward in the fluid column). The present
invention can be utilized to determine whether or not a gas bubble
is present in the fluid column, and to provide a general indication
of the location of the gas bubble within the fluid column. With
this information, the well operator can take precautionary
measurements to prevent loss of control of the well, such as by
increasing or decreasing the "weight" (density) of the fluid
column.
Additional objectives, features and advantages will be apparent in
the written description which follows.
BRIEF DESCRIPTION OF THE DRAWINGS
The novel features believed characteristic of the invention are set
forth in the appended claims. The invention itself, however, as
well as a preferred mode of use, further objectives and advantages
thereof, will best be understood by reference to the following
detailed description of an illustrative embodiment when read in
conjunction with the accompanying drawings, wherein:
FIG. 1 is an overall schematic sectional view illustrating a
potential location within a borehole of an implementation of the
invention;
FIG. 2 is an enlarged schematic view of a portion of the
arrangement shown in FIG. 1;
FIG. 3 is an overall sectional view of an implementation of the
transducer of the instant invention;
FIG. 4 is an enlarged sectional view of a portion of the
construction shown in FIG. 3;
FIG. 5 is a transverse sectional view, taken on a plane indicated
by the lines 5--5 in FIG. 4;
FIG. 6 is a partial, somewhat schematic sectional view showing the
magnetic circuit provided by the implementation illustrated in
FIGS. 3-5;
FIG. 7A is a schematic view corresponding to the implementation of
the invention shown in FIGS. 3-6, and FIG. 7B is a variation on
such implementation;
FIGS. 8 through 11 illustrate various alternate constructions;
FIG. 12 illustrates in schematic form a preferred combination of
such elements;
FIGS. 13A, 13B and 13C provide is an overall sectional view of
another implementation of the instant invention;
FIG. 14 is an enlarged sectional view of a portion of the
construction shown in FIG. 13;
FIGS. 15A-15C illustrate in schematic cross-section various
constructions of a directional coupler portion of the
invention.
FIG. 16 is an overall somewhat diagrammatic sectional view
illustrating an implementation of the invention, a potential
location within a borehole for the same;
FIG. 17 is a block diagram of a preferred embodiment of the
invention;
FIG. 18 is a flow chart depicting the synchronization process of
the downhole acoustic transceiver portion of the preferred
embodiment of FIG. 17;
FIG. 19 is a flow chart depicting the synchronization process of
the surface acoustic transceiver portion of the preferred
embodiment of FIG. 2;
FIG. 20A, 20B, and 20C depict the synchronization signal
structure;
FIG. 21 is a detailed block diagram of the downhole acoustic
transceiver;
FIG. 22 is a detailed block diagram of the surface acoustic
transceiver;
FIG. 23 depicts the second synchronization signals and the
resultant correlation signals;
FIG. 24 depicts the utilization of the transducer and communication
system in the present invention in a drillstring during drilling
operations to transmit data between selected locations in the
drillstring;
FIGS. 25 and 26 are utilized to illustrate the application of the
transducer and communication system of the present invention during
drilling operations for the purpose of identifying and detecting
the influx of gas into a wellbore fluid column; and
FIGS. 27A, 27B and 28 are block diagram representations of an
alternative data communication system for the present
invention.
DETAILED DESCRIPTION OF THE INVENTION
THE TRANSDUCER:
The transducer of the present invention will be described with
references to FIGS. 1 through 15.
With reference to FIG. 1, a borehole, generally referred to by the
reference numeral 11, is illustrated extending through the earth
12. Borehole 11 is shown as a petroleum product completion hole for
illustrative purposes. It includes a casing schematically
illustrated at 13 and production tubing 14 within which the desired
oil or other petroleum product flows. The annular space between the
casing and production tubing is filled with a completion liquid
represented by dots 16. The viscosity of this completion liquid
could be any viscosity within a wide range of possible viscosities.
Its density also could be of any value within a wide range, and it
may include corrosive liquid components like a high density salt
such as a sodium, potassium and/or bromide compound.
In accordance with conventional practice, a packer represented at
17 is provided to seal the borehole and the completion fluid from
the desired petroleum product. The production tubing 14 extends
through the same as illustrated and may include a safety valve,
data gathering instrumentation, or other tools on the petroleum
side of the packer 17.
A carrier 19 for the transducer of the invention is provided on the
lower end of the tubing 14. As illustrated, a transition section 21
and one or more reflecting sections 22 (which will be discussed in
more detail below) separate the carrier from the remainder of the
production tubing. Such carrier includes a slot 23 within which the
communication transducer of the invention is held in a conventional
manner, such as by strapping or the like. A data gathering
instrument, a battery pack, and other components, also could be
housed within slot 23.
It is the completion liquid 16 which acts as the transmission
medium for acoustic waves provided by the transducer, but any other
fluid can be utilized for transmission, including but not limited
to production fluids, drilling fluids, or fresh or salt water.
Communication between the transducer and the annular space which
confines such liquid is represented in FIGS. 1 and 2 by port 24.
Data can be transmitted through the port 24 to the completion
liquid and, hence, by the same in accordance with the invention.
For example, a predetermined frequency band may be used for
signaling by conventional coding and modulation techniques, binary
data may be encoded into blocks, some error checking added, and the
blocks transmitted serially by Frequency Shift Keying (FSK) or
Phase Shift Keying (PSK) modulation. The receiver then will
demodulate and check each block for errors.
The annular space at the carrier 19 is significantly smaller in
cross-sectional area than that of the greater part of the well
containing, for the most part, only production tubing 14. This
results in a corresponding mismatch of acoustic characteristic
admittances. The purpose of transition section 21 is to minimize
the reflections caused by the mismatch between the section having
the transducer and the adjacent section. It is nominally
one-quarter wavelength long at the desired center frequency and the
sound speed in the fluid, and it is selected to have a diameter so
that the annular area between it and the casing 13 is a geometric
average of the product of the adjacent annular areas, (that is, the
annular areas defined by the production tubing 14 and the carrier
19). Further transition sections can be provided as necessary in
the borehole to alleviate mismatches of acoustic admittances along
the communication path.
Reflections from the packer (or the well bottom in other designs)
are minimized by the presence of a multiple number of reflection
sections or steps below the carrier, the first of which is
indicated by reference numeral 22. It provides a transition to the
maximum possible annular area one-quarter wavelength below the
transducer communication port. It is followed by a quarter
wavelength long tubular section 25 providing an annular area for
liquid with the minimum cross-sectional area it otherwise would
face. Each of the reflection sections or steps can be multiple
number of quarter wavelengths long. The sections 19 and 21 should
be an odd number of quarter wavelengths, whereas the section 25
should be odd or even (including zero), depending on whether or not
the last step before the packer 17 has a large or small
cross-section. It should be an even number (or zero) if the last
step before the packer is from a large cross-section to a small
cross-section.
While the first reflection step or section as described herein is
the most effective, each additional one that can be added improves
the degree and bandwidth of isolation. (Both the transition section
21, the reflection section 22, and the tubular section can be
considered as parts of the combination making up the preferred
transducer of the invention.)
A communication transducer for receiving the data is also provided
at the location at which it is desired to have such data. In most
arrangements this will be at the surface of the well, and the
electronics for operation of the receiver and analysis of the
communicated data also are at the surface or in some cases at
another location. The receiving transducer 24 most desirably is a
duplicate in principle of the transducer being described. (It is
represented in FIG. 1 by box 25 at the surface of the well). The
communication analysis electronics is represented by box 10.
It will be recognized by those skilled in the art that the acoustic
transducer arrangement of the invention is not limited necessarily
to communication from downhole to the surface. Transducers can be
located for communication between two different downhole locations.
It is also important to note that the principle on which the
transducer of the invention is based lends itself to two-way
design: a single transducer can be designed to both convert an
electrical communication signal to acoustic communication waves,
and vice versa.
An implementation of the transducer of the invention is generally
referred to by the reference numeral 26 in FIGS. 3 through 6. This
specific design terminates at one end in a coupling or end plug 27
which is threaded into a bladder housing 28. A bladder 29 for
pressure expansion is provided in such housing. The housing 28
includes ports 31 for free flow into the same of the borehole
completion liquid for interaction with the bladder. Such bladder
communicates via a tube with a bore 32 extending through a coupler
33. The bore 32 terminates in another tube 34 which extends into a
resonator 36. The length of the resonator is nominally .lambda./4
in the liquid within resonator 36. The resonator is filled with a
liquid which meets the criteria of having low density, viscosity,
sound speed, water content, vapor pressure and thermal expansion
coefficient. Since some of these requirements are mutually
contradictory, a compromise must be made, based on the condition of
the application and design constraints. The best choices have thus
far ben found among the 200 and 500 series Dow Corning silicone
oils, refrigeration oils such as Capella B and lightweight
hydrocarbons such as kerosene. The purpose of the bladder
construction is to enable expansion of such liquid as necessary in
view of the pressure and temperature of the borehole liquid at the
downhole location of the transducer.
The transducer of the invention generates (or detects) acoustic
wave energy by means of the interaction of a piston in the
transducer housing with the borehole liquid. In this
implementation, this is done by movement of a piston 37 in a
chamber 38 filled with the same liquid which fills resonator 36.
Thus, the interaction of piston 37 with the borehole liquid is
indirect: the piston is not in direct contact with such borehole
liquid. Acoustic waves are generated by expansion and contraction
of a bellows type piston 37 in housing chamber 38. One end of the
bellows of the piston arrangement is permanently fastened around a
small opening 39 of a horn structure 41 so that reciprocation of
the other end of the bellows will result in the desired expansion
and contraction of the same. Such expansion and contraction causes
corresponding flexures of isolating diaphragms 42 in windows 43 to
impart acoustic energy waves to the borehole liquid on the other
side of such diaphragms. Resonator 36 provides a compliant backload
for this piston movement. It should be noted that the same liquid
which fills the chamber of the resonator 36 and chamber 38 fills
the various cavities of the piston driver to be discussed
hereinafter, and the change in volumetric shape of chamber 38
caused by reciprocation of the piston takes place before pressure
equalization can occur.
One way of looking at the resonator is that its chamber 36 acts, in
effect, as a tuning pipe for returning in phase to piston 37 that
acoustical energy which is not transmitted by the piston to the
liquid in chamber 38 when such piston first moves. To this end,
piston 37, made up of a steel bellows 46 (FIG. 4), is open at the
surrounding horn opening 39. The other end of the bellows is closed
and has a driving shaft 47 secured thereto. The horn structure 41
communicates the resonator 36 with the piston, and such resonator
aids in assuring that any acoustic energy generated by the piston
that does not directly result in movement of isolating diaphragms
42 will reinforce the oscillatory motion of the piston. In essence,
its intercepts that acoustic wave energy developed by the piston
which does not directly result in radiation of acoustic waves and
uses the same to enhance such radiation. It also acts to provide a
compliant backload for the piston 37 as stated previously. It
should be noted that the inner wall of the resonator could be
tapered or otherwise contoured to modify the frequency
response.
The driver for the piston will now be described. It includes the
driving shaft 47 secured to the closed end of the bellows. Such
shaft also is connected to an end cap 48 for a tubular bobbin 49
which carries two annular coils or windings 51 and 52 in
corresponding, separate radial gaps 53 and 54 (FIG. 6) of a closed
loop magnetic circuit to be described, but a greater number of
bobbins could be utilized. Such bobbin terminates at its other end
in a second end cap 55 which is supported in position by a flat
spring 56. Spring 56 centers the end of the bobbin to which it is
secured and constrains the same to limited movement in the
direction of the longitudinal axis of the transducer, represented
in FIG. 4 by line 57. A similar flat spring 58 is provided for the
end cap 48.
In keeping with the invention, a magnetic circuit having a
plurality of gaps is defined within the housing. To this end, a
cylindrical permanent magnet 60 is provided as part of the driver
coaxial with the axis 57. Such permanent magnet generates the
magnetic flux needed for the magnetic circuit and terminates at
each of its ends in a pole piece 61 and 62, respectively, to
concentrate the magnetic flux for flow through the pair of
longitudinally spaced apart gaps 53 and 54 in the magnetic circuit.
The magnetic circuit is completed by an annular magnetically
passive member of magnetically permeable material 64. As
illustrated, such member includes a pair of inwardly directed
annular flanges 66 and 67 which terminate adjacent the windings 51
and 52 and define one side of the gaps 53 and 54.
The magnetic circuit formed by this implementation is represented
in FIG. 6 by closed loop magnetic flux lines 68. As illustrated,
such lines extend from the magnet 60, through pole piece 61, across
gap 53 and coil 51, through the return path provided by member 64,
through gap 54 and coil 52, and through pole piece 62 to magnet 60.
With this arrangement, it will be seen that magnetic flux passes
radially outward through gap 53 and radially inward through gap 54.
Coils 51 and 52 are connected in series opposition, so that current
in the same provides additive force on the common bobbin. Thus, if
the transducer is being used to transmit a communication, an
electrical signal defining the same is passed through the coils 51
and 52 will cause corresponding movement of the bobbin 49 and,
hence, the piston 37. Such piston will interact through the windows
43 with the borehole liquid and impart the communicating acoustic
energy thereto. Thus, the electrical power represented by the
electrical signal is converted by the transducer to mechanical
power, in the form of, acoustic waves.
When the transducer receives a communication, the acoustic energy
defining the same will flex the diaphragms 42 and correspondingly
move the piston 37. Movement of the bobbin and windings within the
gaps 51 and 52 will generate a corresponding electrical signal in
the coils 51 and 52 in view of the lines of magnetic flux which are
cut by the same. In other words, the acoustic power is converted to
electrical power.
In the implementation being described, it will be recognized that
the permanent magnet 60 and its associated pole pieces 61 and 62
are generally cylindrical in shape with the axis 57 acting as an
axis of a figure of revolution. The bobbin is a cylinder with the
same axis, with the coils 51 and 52 being annular in shape. Return
path member 64 also is annular and surrounds the magnet, etc. The
magnet is held centrally by support rods 71 projecting inwardly
from the return path member, through slots in bobbin 49. The flat
springs 56 and 58 correspondingly centralize the bobbin while
allowing limited longitudinal motion of the same as aforesaid.
Suitable electrical leads 72 for the windings and other electrical
parts pass into the housing through potted feedthroughs 73.
FIG. 7A illustrates the implementation described above in schematic
form. The resonator is represented at 36, the horn structure at 41,
and the piston at 37. The driver shaft of the piston is represented
at 47, whereas the driver mechanism itself is represented by box
74. FIG. 7B shows an alternate arrangement in which the driver is
located within the resonator 76 and the piston 37 communicates
directly with the borehole liquid which is allowed to flow in
through windows 43. The windows are open; they do not include a
diaphragm or other structure which prevents the borehole liquid
from entering the chamber 38. It will be seen that in this
arrangement the piston 37 and the horn structure 41 provide
fluid-tight isolation between such chamber and the resonator 36. It
will be recognized, though, that it also could be designed for the
resonator 36 to be flooded by the borehole liquid. It is desirable,
if it is designed to be so flooded, that such resonator include a
small bore filter or the like to exclude suspended particles. In
any event, the driver itself should have its own inert fluid system
because of close tolerances, and strong magnetic fields. The
necessary use of certain materials in the same makes it prone to
impairment by corrosion and contamination by particles,
particularly magnetic ones.
FIGS. 8 through 12 are schematic illustrations representing various
conceptual approaches and modifications for the invention,
considered by applicant. FIG. 8 illustrates the modular design of
the invention. In this connection, it should be noted that the
invention is to be housed in a pipe of restricted diameter, but
length is not critical. The invention enables one to make the best
possible use of cross-sectional area while multiple modules can be
stacked to improve efficiency and power capability.
The bobbin, represented at 81 in FIG. 8, carries three separate
annular windings represented at 82-84. A pair of magnetic circuits
are provided, with permanent magnets represented at 86 and 87 with
facing magnetic polarities and poles 88-90. Return paths for both
circuits are provided by an annular passive member 91.
It will be seen that the two magnetic circuits of the FIG. 8
configuration have the central pole 89 and its associated gap in
common. The result is a three-coil driver with a transmitting
efficiency (available acoustic power output/electric power input)
greater than twice that of a single driver, because of the absence
of fringing flux at the joint ends. Obviously, the process of
"stacking" two coil drivers as indicated by this arrangement with
alternating magnet polarities can be continued as long as desired
with the common bobbin being appropriately supported. In this
schematic arrangement, the bobbin is connected to a piston 85 which
includes a central domed part and bellows of the like sealing the
same to an outer casing represented at 92. This flexure seal
support is preferred to sliding seals and bearings because the
latter exhibit restriction that introduced distortion, particularly
at the small displacements encountered when the transducer is used
for receiving. Alternatively, a rigid piston can be sealed to the
case with a bellows and a separate spring or spider used for
centering. A spider represented at 94 can be used at the opposite
end of the bobbin for centering the same. If such spider is metal,
it can be insulated from the case and can be used for electrical
connections to the moving windings, eliminating the flexible leads
otherwise required.
In the alternative schematically illustrated in FIG. 9, the magnet
86 is made annular and it surrounds a passive flux return path
member 91 in its center. Since passive materials are available with
saturation flux densities about twice the remanence of magnets, the
design illustrated has the advantage of allowing a small diameter
of the poles represented at 88 and 90 to reduce coil resistance and
increase efficiency. The passive flux return path member 91 could
be replaced by another permanent magnet. A two- magnet design, of
course, could permit a reduction in length of the driver.
FIG. 10 schematically illustrates another magnetic structure for
the driver. It includes a pair of oppositely radially polarized
annular magnets 95 and 96. As illustrated, such magnets define the
outer edges of the gaps. In this arrangement, an annular passive
magnetic member 97 is provided, as well as a central return path
member 91. While this arrangement has the advantage of reduced
length due to a reduction of flux leakage at the gaps and low
external flux leakage, it has the disadvantage of more difficult
magnet fabrication and lower flux density in such gaps.
Conical interfaces can be provided between the magnets and pole
pieces. Thus, the mating junctions can be made oblique to the long
axis of the transducer. This construction maximizes the magnetic
volume and its accompanying available energy while avoiding
localized flux densities that could exceed a magnet remanence. It
should be noted that any of the junctions, magnet-to-magnet, pole
piece-to-pole piece and of course magnet-to-pole piece can be made
conical. FIG. 11 illustrates one arrangement for this feature. It
should be noted that in this arrangement the magnets may includes
pieces 98 at the ends of the passive flux return member 91 as
illustrated.
FIG. 12 schematically illustrates a particular combination of the
options set forth in FIGS. 8 thorough 11 which could be considered
a preferred embodiment for certain applications. It includes a pair
of pole pieces 101, and 102 which mate conically with radial
magnets 103, 104 and 105. The two magnetic circuits which are
formed include passive return path members 106 and 107 terminating
at the gaps in additional magnets 108 and 110.
An implementation of the invention incorporating some of the
features mentioned above is illustrated in FIGS. 13A, 13B, and 13C
and 14. Such implementation includes two magnetic circuits, annular
magnets defining the exterior of the magnetic circuit and a central
pole piece. Moreover, the piston is in direct contact with the
borehole liquid and the resonant chamber is filled with such
liquid.
The implementation shown in FIGS. 13A, 13B and 13C, and 14 is
similar in many aspects to the implementation illustrated and
described with respect to FIGS. 3 and 6. Common parts will be
referred to by the same reference numerals used earlier but with
the addition of prime component. This implementation includes many
of the features of he earlier one, which features should be
considered as being incorporated within the same, unless indicated
otherwise.
The implementation of FIGS. 13A, 13B and 13C, and 14 is generally
referred to by the reference numeral 120. The resonator chamber 36'
is downhole of this piston 37' and its driver, in this arrangement,
and is allowed to be filled with borehole liquid rather than being
filled with a special liquid as described in connection with the
earlier implementation. The bladder and its associated housing is
eliminated and the end plug 27' is threaded directly into the
resonator chamber 36. Such end plug includes a plurality of
elongated bores 122 which communicate the borehole with tube 34'
extending in to the resonator 36. As with the previously described
implementation, the tube 34' is nominally a quarter of the
communication frequency in the resonator fluid (the borehole liquid
in this implementation). The diameter of the bores 122 is selected
relative to the interior diameter of tube 34' to assure that no
particulate matter of sufficient size from the borehole liquid can
enter and block the tube enter the same.
It will be recognized that while with this arrangement the chamber
36' which provides a compliant backload for movement of the piston
37' is in direct communication with the borehole liquid through the
tube 34', acoustic wave energy in the same will not be transmitted
to the exterior of the chamber because of attenuation by such
tube.
Piston 37' is a bellows as described in the earlier implementation
and acts to isolate the driver for the same to be described from a
chamber 38' which is allowed to be filled with the borehole liquid.
Such chamber 38' is illustrated as having two parts, parts 123 and
124, that communicate directly with one another. As illustrated,
windows 43' extend to the annulus surrounding the transducer
construction without the intermediary of isolating diaphragms as in
the previous implementation. Thus, in this implementation the
piston 37' is in direct contact with borehole liquid which fills
the chamber 38'.
The piston 37' is connected via a nut 127 and driving shaft 128 to
the driver mechanism. To this end, the driving shaft 128 is
connected to an end cap 48' of a tubular bobbin 49'. The bobbin 49'
carries three annular coils or windings in a corresponding number
of radial gaps of two closed loop magnetic circuits to be
described. Two of these windings are represented at 128 and 129.
The third winding is on the axial side of winding 129 opposite that
of winding 128 in accordance with the arrangement shown in FIG. 8.
Moreover, winding 129 is twice the axial length of winding 128. The
bobbin 49' is constrained in position similarly to bobbin 49' by
springs 56' and 58'.
The driver in this implementation conceptually is a hybrid of the
approaches illustrated in FIGS. 8 and 9. That is, it includes two
adjacent magnetic circuits sharing a common pathway. Moreover, the
permanent magnets are annular surrounding a solid core providing a
passive member. In more detail, three magnets illustrated in FIG.
14 at 131, 132 and 133, develop flux which flows across the gaps
within which the windings previously described ride to a solid,
cylindrical core passive member 132. The magnetic circuits are
completed by an annular casing 134 which surrounds the magnets.
Such casing 134 is fluid tight and acts to isolate the driver as
described from the borehole liquid. In this connection, it includes
at its end spaced from piston 37', an isolation bellows 136 which
transmits pressure changes caused in the driver casing 132 to the
resonator 36'. The bellows 136 is free floating in the sense that
it is not physically connected to the tubular bobbin 49' and simply
flexes to accommodate the pressure changes of the special fluid in
the driver casing. It sits within a central cavity or borehole 37
within a plug 38 that extends between the driver casing and the
wall of the resonant chamber 36'. An elongated hole or aperture 139
connects the interior of bellows 136 with the resonator
chamber.
A passive directional coupling arrangement is conceptually
illustrated by FIGS. 15A-15C. The piston of the transducer is
represented at 220. Its design is based on the fact that the
acoustic characteristic admittance in a cylindrical waveguide is
proportional to its cross-sectional area. The windows for
transmission of the communicating acoustic energy to the borehole
fluid are represented at 221. A second port or annular series of
ports 222 are located either three one-quarter wavelength section
(FIG. 15A) or one-quarter wavelength sections (FIGS. 15B and C)
from the windows 221. The coupler is divided into three quarter
wavelength sections 223-226. The cross-sectional area of these
sections are selected to minimize any mismatch which might defeat
directional coupling. Center section 224 has a cross-sectional area
A.sub.3 which is nominally equal to the square of the
cross-sectional area of sections 223 and 226 (A.sub.2) divided by
the annular cross-section of the borehole at the location of the
ports 221 and 222. The reduced cross-sectional area of section 224
is obtained by including an annular restriction 227 in the
same.
The directional coupler is in direct contact with the backside of
the piston 220, with the result that acoustic wave energy will be
introduced into the coupler which is 180.degree. out-of-phase with
that of the desired communication. The relationship of the
cross-sectional areas described previously will assure that the
acoustic energy which emanates from the port 222 will cancel any
transmission from port 221 which otherwise would travel toward port
222.
The version of the directional coupler represented in FIG. 15A is
full length, requiring a three-quarter wavelength long tubing,
i.e., the chamber is divided into three, quarter-wavelength-long
sections. The versions represented in FIGS. 15B and 15C are folded
versions, thereby reducing the length required. That is, the
version in FIG. 15B is folded once with the sectional areas of the
sections meeting the criteria discussed previously. Two of the
chamber sections are coaxial with one another. The version
represented in FIG. 15C is folded twice. That is, all three
sections are coaxial. The two versions in FIGS. 15B and 15C are
one-fourth wavelength from the port 222 and thus are on the
"uphole" side of port 221 as illustrated. It will be recognized,
though, that the bandwidth of effective directional coupling is
reduced with folding.
It will be recognized that in any of the configurations of FIGS.
15A-15C, the port 222 could contain a diaphragm or bellows, an
expansion chamber could be added, and a filling fluid other than
well fluid could be used. Additional contouring of area could also
be done to modify coupling bandwidth and efficiency. Shaping of
ports and arraying of multiple ports could also be done for the
same purpose.
Directional coupling also could be obtained by using two or more
transducers of the invention as described with ports axially
separated to synthesize a phased array. The directional coupling
would be achieved by driving each transducer with a signal
appropriately predistorted in phase and amplitude. Such active
directional coupling can be achieved over a wider bandwidth than
that achieved with a passive system. Of course, the predistortion
functions would have to account for all coupled resonances in each
particular situation.
THE COMMUNICATION SYSTEM:
The communication system of the present invention will be described
with reference to FIGS. 16 through 23.
With reference to FIG. 16, a borehole, generally referred to by the
reference numeral 1100, is illustrated extending through the earth
1102. Borehole 1100 is shown as a petroleum product completion hole
for illustrative purposes. It includes a casing schematically
illustrated at 1104 and production tubing 1106 within which the
desired oil or other petroleum product flows. The annular space
between the casing and production tubing is filled with borehole
completion liquid represented by dots 1108. The properties of a
completion fluid vary significantly from well to well and over time
in any specific well. It typically will include suspended particles
or partially be a gel. It is non-Newtonian and may include
non-linear elastic properties. Its viscosity could be any viscosity
within a wide range of possible viscosities. Its density also could
be of any value within a wide range, and it may include corrosive
solid or liquid components like a high density salt such as a
sodium, calcium, potassium and/or a bromide compound.
A carrier 1112 for a downhole acoustic transceiver (DAT) and its
associated transducer is provided on the lower end of the tubing
1106. As illustrated, a transition section 1114 and one or more
reflecting sections 1116, most desirably are included and separate
carrier 1112 from the remainder of production tubing 1106. Carrier
1112 includes numerous slots in accordance with conventional
practice, within one of which, slot 1118, the communication
transducer (DAT) of the invention is held by strapping or the like.
One or more data gathering instruments or a battery pack also could
be housed within slots like slot 1118. In the preferred embodiment,
one slot is utilized to house a battery pack, and another slot
(slot 1118) is utilized to house the transducer and associated
electronics. It will be appreciated that a plurality of slots could
be provided to serve the function of slot 1118. The annular space
between the casing and the production tubing is sealed adjacent the
bottom of the borehole by packer 1110. The production tubing 1106
extends through the packer and a safety valve, data gathering
instrumentation, and other wellbore tools, may be included.
It is the completion liquid 1108 which acts as the transmission
medium for acoustic waves provided by the transducer. Communication
between the transducer and the annular space which confines such
liquid is represented in FIG. 16 by port 1120. Data can be
transmitted through the port 1120 to the completion liquid via
acoustic signals. Such communication does not rely on flow of the
completion liquid.
A surface acoustic transceiver (SAT) 1126 is provided at the
surface, communicating with the completion liquid in any convenient
fashion, but preferably utilizing a transducer in accordance with
the present invention. The surface configuration of the production
well is diagrammatically represented and includes an end cap on
casing 1104. The production tubing 1106 extends through a seal
represented at 1122 to a production flow line 1123. A flow line for
the completion fluid 1124 is also illustrated, which extends to a
conventional circulation system.
In its simplest form, the arrangement converts information laden
data into an acoustic signal which is coupled to the borehole
liquid at one location in the borehole. The acoustic signal is
received at a second location in the borehole where the data is
recovered. Alternatively, communication occurs between both
locations in a bidirectional fashion. And as a further alternative,
communication can occur between multiple locations within the
borehole such that a network of communication transceivers are
arrayed along the borehole. Moreover, communication could be
through the fluid in the production tubing through the product
which is being produced. Many of the aspects of the specific
communication method described are applicable as mentioned
previously to communication through other transmission medium
provided in a borehole, such as in the walls of the tubing
1106.
Referring to FIG. 17, the downhole acoustic transducer (DAT) 1200
at the downhole location is coupled to a downhole acoustic
transceiver (DAT) data acquisition system 1202 for acoustically
transmitting data collected from the DAT's associated sensors 1201.
The downhole acoustic transceiver (DAT) data acquisition system
1202 includes signal processing circuitry, such as impedance
matching circuits, amplifier circuits, filter circuits,
analog-to-digital conversion circuits, power supply circuits, and a
microprocessor and associated circuitry. The DAT 1202 is capable of
both modulating an electrical signal used to stimulate the
transducer 1200 for transmission, and of demodulating signals
received by the transducer 1200 from the surface acoustic
transceiver (SAT) 1204 data acquisition system. The surface
acoustic transceiver (SAT) data acquisition system 1204 includes
signal processing circuitry, such as impedance matching circuits,
amplifier circuits, filter circuits, analog-to-digital conversion
circuits, power supply circuits, and a microprocessor and
associated circuitry. In other words, the DAT 1202 both receives
and transmits information. Similarly, the SAT 1204 both receives
and transmits information. The communication is directly between
the DAT 1202 and the SAT 1204 through transducers 1200, 1205.
Alternatively, intermediary transceivers could be positioned within
the borehole to accomplish data relay. Additional DATs could also
be provided to transmit independently gathered data from their own
sensors to the SAT or to another DAT.
More specifically, the bi-directional communication system of the
invention establishes accurate data transfer by conducting a series
of steps designed to characterize the borehole communication
channel 1206, choose the best center frequency based upon the
channel characterization, synchronize the SAT 1204 with the DAT
1202, and, finally, bi-directionally transfer data. This complex
process is undertaken because the channel 1206 through which the
acoustic signal must propagate is dynamic, and this time variant.
Furthermore, the channel is forced to be reciprocal: the
transducers are electrically loaded as necessary to provide for
reciprocity.
In an effort to mitigate the effects of the channel interference
upon the information throughput, the inventive communication system
characterizes the channel in the uphole direction 1210. To do so,
the DAT 1202 sends a repetitive chirp signal which the SAT 1204, in
conjunction with its computer 1128, analyzes to determine the best
center frequency for the system to use for effective communication
in the uphole direction. Currently, the channel 1210 is
characterized only in the uphole direction; thus, an implicit
assumption of reciprocity is incorporated into the design. It will
be recognized that the downhole direction 1208 could be
characterized rather than, or in addition to, characterization for
uphole communication. Moreover, in the current design, the bit rate
of the data transmitted by the DAT 1202 may be higher than the
commands sent by the SAT 1204 to the DAT 1202. Thus, it is
advantageous to achieve the best signal to noise ratio for the
uphole signals.
Alternatively, if reciprocity is not met, each transceiver could be
designed to characterize the channel in the incoming communication
direction: the SAT 1204 could analyze the channel for uphole
communication 1210 and the DAT 1202 could analyze for downhole
communication 1208, and then command the corresponding transmitting
system to use the best center frequency for the direction
characterized by it. However, this alternative would require extra
processing capability in the DAT 1202. Extra processing capability
means greater power and size requirements which are, in most
instances, undesirable.
In addition to choosing a proper channel for transmission, system
timing synchronization is important to any coherent communication
system. To accomplish the channel characterization and timing
synchronization processes together, the DAT begins transmitting
repetitive chirp sequences after a programmed time delay selected
to be longer than the expected lowering time.
FIGS. 20A-C depict the signalling structure for the chirp
sequences. In a preferred implementation, a single chirp block is
one hundred milliseconds in duration and contains three cycles of
one hundred fifty (150) Hertz signal, four cycles of two hundred
(200) Hertz signal, five cycles of two hundred and fifty (250)
Hertz signal, six cycles of three hundred (300) Hertz signal, and
seven cycles of three hundred and fifty (350) Hertz cycles. The
chirp signal structure is depicted in FIG. 20A. Thus, the entire
bandwidth of the desired acoustic channel, one hundred and fifty to
three hundred and fifty (150-350) Hertz, is chirped by each
block.
As depicted in FIG. 20B, the chirp block is repeated with a time
delay between each block. As shown in FIG. "20C", this sequence is
repeated three times at two minute intervals. The first two
sequences are transmitted sequentially without any delay between
them, then a delay is created before a third sequence is
transmitted. During most of the remainder of the interval, the DAT
1202 waits for a command (or default tone) from the SAT 1204. The
specific sequence of chirp signals should not be construed as
limiting the invention: variations on the basic scheme, including
but not limited to different chirp frequencies, chirp durations,
chirp pulse separations, etc., are foreseeable. It is also
contemplated that PN sequences, an impulse, or any variable signal
which occupies the desired spectrum could be used.
The SAT 1204 of the preferred embodiment of the invention uses two
microprocessors 1616, 1626 to effectively control the SAT
functions, as is illustrated in FIG. 22. The host computer 1128
controls all of the activities of the SAT 1204 and is connected
thereto via one of two serial channels of a Model 68000
microprocessor 1626 in the SAT 1204. In alternative embodiments,
the SAT 1204 may be mounted on an input/output card which is
adapted in size to be inserted within an expansion slot of a host
computer. The 68000 microprocessor accomplishes the bulk of the
signal processing functions that are discussed below. The second
serial channel of the 68000 microprocessor is connected to a 68HC11
processor 1616 that controls the signal digitization, the retrieval
of received data, and the sending of tones and commands to the DAT.
The chirp sequence is received from the DAT by the transducer 1205
and converted into an electrical signal from an acoustic signal.
The electrical signal is coupled to the receiver through
transformer 1600 which provides impedance matching. Amplifier 1602
increases the signal level, and the bandpass filter 1604 limits the
noise bandwidth to three hundred and fifty (350) Hertz centered at
two hundred and fifty (250) Hertz and also functions as an
anti-alias filter. Of course, different or additional bandwidths
between as large as one kilohertz to as small as one Hertz could be
utilized in alternative embodiments of the present invention, but
for purposes of this written description, the range of frequencies
between one hundred Hertz and three hundred Hertz will be discussed
and utilized as an example, and not as a limitation of the present
invention.
Referring to FIG. 21, the DAT 1202 has a single 68HC11
microprocessor 1512 that controls all transceiver functions, the
data logging activities, logged data retrieval and transmission,
and power control. For simplicity, all communications are
interrupt-driven. In addition, data from the sensors are buffered,
as represented by block 1510, as it arrives. Moreover, the commands
are processed in the background by algorithms 1700 which are
specifically designed for that purpose.
The DAT 1202 and SAT 1204 include, though not explicitly shown in
the block diagrams of FIGS. 21 and 22, all of the requisite
microprocessor support circuitry. These circuits, including RAM,
ROM, clocks, and buffers, are well known in the art of
microprocessor circuit design.
Generation of the chirp sequence is accomplished by a digital
signal generator controlled by the DAT microprocessor 1512.
Typically, the chirp block is generated by a digital counter having
its output controlled by a microprocessor to generate the complete
chirp sequence. Circuits of this nature are widely used for
variable frequency clock signal generation. The chirp generation
circuitry is depicted as block 1500 in FIG. 21, a block diagram of
the DAT 1202. Note that the digital output is used to generate a
three level signal at 1502 for driving the transducer 1200. It is
chosen for this application to maintain most of the signal energy
in the acoustic spectrum of interest: one hundred and fifty Hertz
to three hundred and fifty Hertz. The primary purpose of the third
state is to terminate operation of the transmitting portion of a
transceiver during its receiving mode: it is, in essence, a short
circuit.
FIG. 18 and FIG. 19 are flow charts of the DAT and SAT operations,
respectively. The chirp sequences are generated during step 1300.
Prior to the first chirp pulse being transmitted after the selected
time delay, the surface transceiver awaits the arrival of the chirp
sequences in accordance with step 1400 in FIG. 19. The DAT is
programmed to transmit a burst of chirps every two minutes until it
receives two tones: fc and fc+1. Initial synchronization starts
after a "characterize channel" command is issued at the host
computer. Upon receiving the "characterize channel" command, the
SAT starts digitizing transducer data. The raw transducer data is
conditioned through a chain of amplifiers, anti-aliasing filters,
and level translators, before being digitized. One second data
block (1024 samples) is stored in a buffer and pipelined for
subsequent processing.
The functions of the chirp correlator are threefold. First, it
synchronizes the SAT TX/RX clock to that of the DAT. Second, it
calculates a clock error between the SAT and DAT timebases, and
corrects the SAT clock to match that of the DAT. Third, it
calculates a one Hertz resolution channel spectrum.
The correlator performs a FFT ("Fast Fourier Transform") on a 0.25
second data block, and retains FFT signal bins between one hundred
and forty Hertz to three hundred and sixty Hertz. The complex
valued signal is added coherently to a running sum buffer
containing the FFT sum over the last six seconds (24 FFTs). In
addition, the FFT bins are incoherently added as follows: magnitude
squared, to a running sum over the last 6 seconds. An estimate of
the signal to noise ratio (SNR) in each frequency bin is made by a
ratio of the coherent bin power to an estimated noise bin power.
The noise power in each frequency bin is computed as the difference
of the incoherent bin power minus the coherent bin power. After the
SNR in each frequency bin is computed, an "SNR sum" is computed by
summing the individual bin SNRs. The SNR sum is added to the past
twelve and eighteen second SNR sums to form a correlator output
every 0.25 seconds and is stored in an eighteen second circular
buffer. In addition, a phase angle in each frequency bin is
calculated from the six second buffer sum and placed into an
eighteen second circular phase angle buffer for later use in clock
error calculations.
After the chirp correlator has run the required number of seconds
of data through and stored the results in the correlator buffer,
the correlator peak is found by comparing each correlator point to
a noise floor plus a preset threshold. After detecting a chirp, all
subsequent SAT activities are synchronized to the time at which the
peak was found.
After the chirp presence is detected, an estimate of sampling clock
difference between the SAT and DAT is computed using the eighteen
second circular phase angle buffer. Phase angle difference
(.box-solid..phi.) over a six second time interval is computed for
each frequency bin. A first clock error estimation is computed by
averaging the weighted phase angle difference over all the
frequency bins. Second and third clock error estimations are
similarly calculated respectively over twelve and one hundred and
eighty-five second time intervals. A weighted average of three
clock error estimates gives the final clock error value. At this
point in time, the SAT clock is adjusted and further clock
refinement is made at the next two minute chirp interval in similar
fashion.
After the second clock refinement, the SAT waits for the next set
of chirps at the two minute interval and averages twenty-four 0.25
second chirps over the next six seconds. The averaged data is zero
padded and then FFT is computed to provide one Hertz resolution
channel spectrum. The surface system looks for a suitable
transmission frequency in the one hundred and fifty Hertz to three
hundred and fifty Hertz. Generally, a frequency band having a good
signal to noise ratio and bandwidths of approximately two Hertz to
forty Hertz is acceptable. A width of the available channel defines
the acceptable baud rate.
The second phase of the initial communication process involves
establishing an operational communication link between the SAT 1204
and the DAT 1202. Toward this end, two tones, each having a
duration of two seconds, are sequentially sent to the DAT 1202. One
tone is at the chosen center frequency and the other is offset from
the center frequency by exactly one hertz. This step in the
operation of the SAT 1204 is represented by block 1406 in FIG.
19.
The DAT is always looking for these two tones: fc and fc+1, after
it has stopped chirping. Before looking for these tones, it
acquires a one second block of data at a time when it is known that
there is no signal. The noise collection generally starts six
seconds after the chirp ends to provide time for echoes to die
down, and continues for the next thirty seconds. During the thirty
second noise collection interval, a power spectrum of one second
data block is added to a three second long running average power
spectrum as often as the processor can compute the 1024 point (one
second) power spectrum.
The DAT starts looking for the two tones approximately thirty-six
seconds after the end of the chirp and continues looking for them
for a period of four seconds (tone duration) plus twice the maximum
propagation time. The DAT again calculates the power spectrum of
one second blocks as fast as it can, and computes signal to noise
ratios for each one Hertz wide frequency bins. All the frequency
components which are a preset threshold above a noise floor are
possible candidates. If a frequency is a candidate in two
successive blocks, then the tone is detected at its frequency. If
the tones are not recognized, the DAT continues to chirp at the
next two minute interval. When the tones are received and properly
recognized by the DAT, the DAT transmits the same two tones back to
the SAT at the selected carrier frequency fc, which is recognized
as an acknowledgement signal. Then, the SAT transmits characters to
the DAT, which causes the DAT to look for a coded "recognition
sequence signal". Control data follows the recognition signal.
Preferably, the recognition sequence signal includes a baud rate
signal which identifies to the DAT the expected baud rate, as
determined by the SAT. The DAT will then respond to any command
provided to it after the recognition sequence signal. Typically,
the SAT will command the DAT to begin the transmission of data from
the downhole location for receipt by the SAT at the uphole
location.
A by-product of the process of recognizing the tones is that it
enables the DAT to synchronize its internal clock to the surface
transceiver's clock. Using the SAT clock as the reference clock,
the tone pair can be said to begin at time t=0. Also assume that
the clock in the surface transceiver produces a tick every second
as depicted in FIG. 23. This alignment is desirable to enable each
clock to tick off seconds synchronously and maintain coherency for
accurately demodulating the data. However, the DAT is not sure when
it will receive the pair, so it conducts an FFT every second
relative to its own internal clock which can be assumed not to be
aligned with the surface clock. When the four seconds of tone pair
arrive, they will more than likely cover only three one second FFT
interval fully and only two of those will contain a single
frequency. FIG. 23 is helpful in visualizing this arrangement. Note
that the FFT periods having a full one second of tone signal
located within it will produce a maximum FFT peak.
Once received, an FFT of each two second tone produces both
amplitude and phase components of the signal. When the phase
component of the first signal is compared with the phase component
of the second signal, the one second ticks of the downhole clock
can be aligned with the surface clock. For example, a two hundred
Hertz tone followed immediately by a two hundred and one Hertz tone
is sent from the transceiver at time t=0. Assume that the
propagation delay is one and one-half seconds and the difference
between the one second ticking of the clocks is 0.25 seconds. This
interval is equivalent to three hundred and fifty cycles of two
hundred Hertz Hz signal and 351.75 cycles of two hundred and one
Hertz tone. Since an even number of cycles has passed for the first
tone, its phase will be zero after the FFT is accomplished.
However, the phase of the second tone will be two hundred and
seventy degrees from that of the first tone. Consequently, the
difference between the phases of each tone is two hundred and
seventy degrees which corresponds to an offset of 0.75 seconds
between the clocks. If the DAT adjusts its clock by 0.75 seconds,
the one second ticks will be aligned. In general, the phase
difference defines the time offset. This offset is corrected in
this implementation. The timing correction process is represented
by step 1308 in FIG. 18 and is accomplished by the software in the
DAT, as represented by blocks 1504, 1506, 1508 in the DAT block
diagram of FIG. 21.
It should be noted that the tones are generated in both the DAT and
SAT in the same manner as the chirp signals were generated in the
DAT. As described previously, in the preferred embodiment of the
invention, a microprocessor controlled digital signal generator
1500, 1628 creates a pulse stream of any frequency in the band of
interest. Subsequent to generation, the tones are converted into a
three level signal at 1502, 1630 for transmission by the transducer
1200, 1205 through the acoustic channel.
After tone recognition and retransmission, the DAT adjusts its
clock, then switches to the Minimum Shift Keying (MSK) modulation
receiving mode. (Any modulation technique can be used, although it
is preferred that MSK be used for the invention for the reasons
discussed below.) Additionally, if the tones are properly
recognized by the SAT as being identical to the tones which were
sent (step 1408), it transmits a MSK modulated command instructing
the DAT as to what baud rate the downhole unit should use to send
its data to achieve the best bit energy to noise ratio at the SAT
(step 1410). The DAT is capable of selecting 2 to 40 baud in 2 baud
increments for its transmissions. The communication link in the
downhole direction is maintained at a two baud rate, which rate
could be increased if desired. Additionally, the initial message
instructs the downhole transceiver of the proper transmission
center frequency to use for its transmissions.
If, however, the tones are not received by the downhole
transceiver, it will revert to chirping again. SAT did not receive
the two tone acknowledgement signal since DAT did not transmit
them. In this case the operator can either try sending tones
however many times he wants to or try recharacterizing channel
which will essentially resynchronize the system. In the case of
sending two tones again, SAT will wait until the next tone transmit
time during which the DAT would be listening for the tones.
If the downhole transceiver receives the tones and retransmits
them, but the SAT does not detect them, the DAT will have switched
to this MSK mode to await the MSK commands, and it will not be
possible for it to detect the tones which are transmitted a second
time, if the operator decides to retransmit rather than to
recharacterize. Therefore, the DAT will wait a set duration. If the
MSK command is not received during that period, it will switch back
to the synchronization mode and begin sending chirp sequences every
two minutes. This same recovery procedure will be implemented if
the established communication link should subsequently
deteriorate.
As previously mentioned, the commands are modulated in an MSK
format. MSK is a form of modulation which, in effect, is binary
frequency shift keying (FSK) having continuous phase during the
frequency shift occurrences. As mentioned above, the choice of MSK
modulation for use in the preferred embodiment of the invention
should not be construed as limiting the invention. For example,
binary phase shift keying (BPSK), quadrature phase shift keying
(QPSK), or any one of the many forms of modulation could be used in
this acoustic communication system.
In the preferred embodiment, the commands are generated by the host
computer 1128 as digital words. Each command is encoded by a
cyclical redundancy code (CRC) to provide error detection and
correction capability. Thus, the basic command is expanded by the
addition of the error detection bits. The encoded command is sent
to the MSK modulator portion of the 68HC11 microprocessor's
software. The encoded command bits control the same digital
frequency generator 1628 used for tone generation to generate the
MSK modulated signals. In general, each encoded command bit is
mapped, in this implementation, onto a first frequency and the next
bit is mapped to a second frequency. For example, if the channel
center frequency is two hundred and thirteen Hertz, the data may be
mapped onto frequencies two hundred and eighteen Hertz,
representing a "1", and two hundred and eight Hertz, representing a
"0". The transitions between the two frequencies are phase
continuous.
Upon receiving the baud rate command, the DAT will send an
acknowledgement to the SAT. If an acknowledgement is not received
by the SAT, it will resend the baud rate command if the operator
decides to retry. If an operator wishes, the SAT can be commanded
to resynchronize and recharacterize with the next set of
chirps.
A command is sent by the SAT to instruct the DAT to begin sending
data. If an acknowledgement is not received, the operator can
resend the command if desired. The SAT resets and awaits the chirp
signals if the operator decides to resynchronize. However, if an
acknowledgement is sent from the DAT, data are automatically
transmitted by the DAT directly following the acknowledgement. Data
are received by the SAT at the step represented at 1434.
Nominally, the downhole transceiver will transmit for four minutes
and then stop and listen for the next command from the SAT. Once
the command is received, the DAT will transmit another 4 minute
block of data. Alternatively, the transmission period can be
programmed via the commands from the surface unit.
It is foreseeable that the data may be collected from the sensors
1201 in the downhole package faster than they can be sent to the
surface. Therefore, as shown in FIG. 21, the DAT may include buffer
memory 1510 to store the incoming data from the sensors 1201 for a
short duration prior to transmitting it to the surface.
The data is encoded and MSK modulated in the DAT in the same manner
that the commands were encoded and modulated in the SAT, except the
DAT may use a higher data rate: two to forty baud, for
transmission. The CRC encoding is accomplished by the
microprocessor 1512 prior to modulating the signals using the same
circuitry 1500 used to generate the chirp and tone bursts. The MSK
modulated signals are converted to tri-state signals 1502 and
transmitted via the transducer 1200.
In both the DAT and the SAT, the digitized data are processed by a
quadrature demodulator. The sine and cosine waveforms generated by
oscillators 1635, 1636 are centered at the center frequency
originally chosen during the synchronization mode. Initially, the
phase of each oscillator is synchronized to the phase of the
incoming signal via carrier transmission. During data recovery, the
phase of the incoming signal is tracked to maintain synchrony via a
phase tracking system such as a Costas loop or a squaring loop.
The I and Q channels each use finite impulse response (FIR) low
pass filters 1638 having a response which approximately matches the
bit rate. For the DAT, the filter response is fixed since the
system always receives thirty-two bit commands. Conversely, the SAT
receives data at varying baud rates; therefore, the filters must be
adaptive to match the current baud rate. The filter response is
changed each time the baud rate is changed.
Subsequently, the I/Q sampling algorithm 1640 optimally samples
both the I and Q channels at the apex of the demodulated bit.
However, optimal sampling requires an active clock tracking
circuit, which is provided. Any of the many traditional clock
tracking circuits would suffice: a tau-dither clock tracking loop,
a delay-lock tracking loop, or the like. The output of the I/Q
sampler is a stream of digital bits representative of the
information.
The information which was originally transmitted is recovered by
decoding the bit stream. To this end, a decoder 1642 which matches
the encoder used in the transmitter process: a CRC decoder, decodes
and detects errors in the received data. The decoded information
carrying data is used to instruct the DAT to accomplish a new task,
to instruct the SAT to receive a different baud rate, or is stored
as received sensor data by the SAT's host computer.
The transducer, as the interface between the electronics and the
transmission medium, is an important segment of the current
invention; therefore, it was discussed separately above. An
identical transducer is used at each end of the communications link
in this implementation, although it is recognized that in many
situations it may be desirable to use differently configured
transducers at the opposite ends of the communication link. In this
implementation, the system is assured when analyzing the channel
that the link transmitter and receiver are reciprocal and only the
channel anomalies are analyzed. Moreover, to meet the environmental
demands of the borehole, the transducers must be extremely rugged
or reliability is compromised.
THE MEASUREMENT-WHILE-DRILLING APPLICATION:
In the foregoing description, the transducer and communication
system are described as being used in a producing wellbore.
However, the transducer and communication system can also be
utilized in a wellbore during completion operations or drilling
operations. FIG. 24 shows one such utilization of the transducer
and communication system during drilling operations. As is shown,
wellbore 601 extends from surface 603 to bottom hole 605.
Drillstring 607 is disposed therein, and is composed of a section
of drill pipe 609 and a section of drill collar 611. The drill
collar 611 is located at the lowermost portion of drillstring 607,
and terminates at its lowermost end at rockbit 613. As is
conventional, during drilling operations, fluid is circulated
downward through drillstring 607 to cool and lubricate drillbit
613, and to wash formation cuttings upward through annulus 615 of
wellbore 601.
Typically, one of two types of drillbits are utilized for drilling
operations, including: (a) a rolling-cone type drillbit, which
requires that drillstring 607 be rotated at surface 603 to cause
disintegration of the formation at bottom hole 605, and (b) a drag
bit which includes cutters which are disposed in a fixed position
relative to the bit, and which is rotated by rotation of
drillstring 607 or by rotation of a portion of drill collar 611
through utilization of a motor.
In either event, a fluid column exists within drillstring 607, and
a fluid column exists within annulus 615 which is between
drillstring 607 and wellbore 601. It is common during conventional
drilling operations to utilize a measurement-while-drilling data
transmission system which impresses a series of either positive or
negative pressure pulses upon the fluid within annulus 615 to
communicate data from drill collar section 611 to surface 603.
Typically, a measurement-while-drilling data transmission system
includes a plurality of instruments for measuring drilling
conditions, such as temperature and pressure, and formation
conditions such as formation resistivity, formation gamma ray
discharge, and formation dielectric properties. It is conventional
to utilize measurement-while-drilling systems to provide to the
operator at the surface information pertaining to the progress of
the drilling operations as well as information pertaining to
characteristics or qualities of the formations which have been
traversed by rockbit 613.
In FIG. 24, measurement-while-drilling subassembly 617 includes
sensors which detect information pertaining to drilling operations
and surrounding formations, as well as the data processing and data
transmission equipment necessary to coherently transmit data from
drill collar 611 to surface 603.
A great need exists in the drilling industry for additional
information, and in particular information which can be
characterized as "near-drillbit" information. This is particularly
true for drilling configurations which utilize steering
subassemblies, such as steering subassembly 621, which allow for
the drilling of directional wells. The utilization of steering
equipment ensures that the measurement-while-drilling data
gathering and transmission equipment is located thirty to sixty
(30-60) feet from drill bit 613. Directional turns of drillbit 613
cannot be accurately monitored and controlled utilizing the sensing
and data transmission equipment of measurement-while-drilling
system 617; near drillbit information would be required in order to
have a higher degree of control. Some examples of desirable near
drillbit data include: inclination of the lowermost portion of the
drilling subassembly, the azimuth of the lowermost portion of the
drilling subassembly, drillbit temperature, mud motor or turbine
rpm, natural gamma ray readings for freshly drilled formations near
the bit, resistivity readings for freshly drilled formations near
the bit, the weight on the bit, and the torque on the bit.
In the present invention, measurement subassembly 619 is located
adjacent rockbit 613, and includes a plurality of conventional
instruments for measuring near drillbit data such as inclination,
azimuth, bit temperature, turbine rpm, gamma ray activity,
formation resistivity, weight on bit, and torque on bit, etc. This
information may be digitized and multiplexed in a conventional
fashion, and directed to acoustic transducer 623 which is located
in an adjacent subassembly for transmission to receiver 625, which
is located upward within the string, and which is adjacent
measurement-while-drilling subassembly 617. In this configuration,
near-drillbit data may be transmitted a short distance (typically
thirty to ninety feet) between transmitter 623 and receiver 625
which utilize the transducer of the present invention as well as
the communication system of the present invention.
The communication system of the present invention continually
monitors the fluid within annulus 615 with a characterization
signal to identify the optimum frequencies for communication, as
was discussed above. The data may be routed from receiver 625 to
measurement-while-drilling system 617 for storage, processing, and
retransmission to surface 603 utilizing conventional
measurement-while-drilling data transmission technologies. This
provides an economical and robust data communication system for the
dynamic and noisy environment adjacent drill collar section 611,
which allows communication of near-drillbit data for integration
into a conventional data stream from a measurement-while-drilling
data communication system.
Alternatively, or additionally, transducer 627 may be provided at
surface 603 for receipt of acoustic data signals from either one or
both of transducer 623 or transducer 625. Or, alternatively, and
more likely, transducer 625 may be utilized to transmit to an
intermediate transducer located in the drillpipe section 609 of the
drillstring 611 which will be able to transmit a greater distance
than transducers located in the drill collar section 611. In this
manner, the transducers and communication system of the present
invention may be utilized as a data transmission system which is
parallel with a conventional measurement-while-drilling data
transmission system. This is particularly useful, since
conventional measurement-while-drilling systems require the
continuous flow of fluid downward through drillstring 607. During
periods of noncirculation or if circulation is lost, conventional
measurement-while-drilling systems cannot communicate data from
wellbore 601 to surface 603, since no fluid is flowing. The
transducer and communication system of the present invention
provide a redundant system which can be utilized to transmit data
to surface 603 during quiescent periods when no fluid is being
circulated within the wellbore. This provides considerable
advantages since there are significant periods of time during which
data communication is not possible during drilling operations
utilizing conventional measurement-while-drilling technologies. In
alternative embodiments, the transducer and communication system of
the present invention can be utilized to completely replace a
conventional measurement-while drilling data transmission system,
and provide a sole mechanism for the communication of data and
control systems within the wellbore during drilling operations.
THE GAS INFLUX DETECTION APPLICATION:
The transducer and communication system of the present invention
can also be utilized during drilling operations for the detection
of the undesirable influx of high pressure gas into the annulus of
a wellbore. As is known to those skilled in the art, the
introduction of high pressure gas into the fluid column of a
wellbore during drilling operations can result in loss of control
of the well, or even a "blowout" in the most extreme situations.
Considerable effort has been expended to provide safety equipment
at the wellhead which can be utilized to prevent the total loss of
control of a well. Once a drilling operator has determined that an
influx of gas is likely to have occurred, remedial actions can be
taken to lessen the impact of the gas influx. Such remedial actions
include increasing or decreasing circulation within the well, or
increasing the viscosity and density of the drilling fluid within
the well. Finally, safety equipment can be utilized to prevent
total loss of control within a wellbore due to a significant gas
influx. The prior art technology is entirely inadequate in
providing sufficient data to the operator during drilling
operations which would allow the operator to avoid the many
problems associated with gas influx. Fortunately, the transducer
and communication system of the present invention can be utilized
in drilling operations to provide the operator with significant
data pertaining to (1) whether an undesirable influx of gas has
occurred, and (2) the location of the gas "bubble" once it has
entered the drilling fluid column. It is important to note that an
influx usually occurs as an introduction of a fluid slug, which is
the gas in liquified form due to the high pressure exerted by the
fluid column. Since the gas generally has a lower density, it will
rise within the fluid column; as it rises, it will come out of
solution, and take the form of a gas "bubble".
In accordance with the present invention, an influx of gas can be
detected in a fluid column within a wellbore which defines a
communication channel by performing the following steps:
(1) at least one actuator is provided in communication with the
wellbore for conversion of at least one of (a) a provided coded
electrical signal to a corresponding generated coded acoustic
signal during a message transmission mode of operation, and (b) a
provided coded acoustic signal to a corresponding generated coded
electrical signal during a message reception mode of operation;
preferably, only one actuator/transducer is provided, and this is
located at the surface of the wellbore at the wellhead, and is in
fluid communication with the fluid column within the annulus of the
wellbore, although in alternative embodiments one or more
transducers may be provided downhole within the drillstring;
(2) the transducer is utilized to generate an interrogating signal
at a selected location within the wellbore; the characterizing
signal may be a "chirp" which includes a plurality of signal
components, each having a different frequency, and spanning over a
preselected range of frequencies, or it may be an acoustic signal
which includes only a single frequency component;
(3) the transducer is utilized to apply the interrogating signal to
the communication channel which is defined, preferably, in the
fluid column within the wellbore annulus;
(4) the interrogating signal is transmitted through the
communication channel and is received by either a different
transducer, or is echoed back upward through the communication
channel and received by the transmitting transducer;
(5) next, the interrogating signal is analyzed to identify at least
one of the following: (a) portions of a preselected range of
frequencies which are suitable for communicating data in the
wellbore; these portions may be identified by either frequency or
bandwidth or both, or by signal-to-noise characteristics such as a
signal-to-noise ratio, or signal amplitude; (b) communication
channel attributes, such as communication channel length, or
communication channel impedance; (c) signal attributes, such as
signal amplitude, signal phase, and the occurrence of loss of the
signal;
(6) Finally, the steps of utilizing, applying, receiving, and
analyzing are repeated periodically to identify changes in at least
one of: (a) portions of the preselected range of frequencies which
are suitable for communicating data in the wellbore including
frequency changes, bandwidth changes, changes in a signal-to-noise
characteristic, changes in signal amplitude of signals transmitted
within the portion, and signal time delays for signals transmitted
within the portion, (b) communication channel attributes, including
changes in communication channel length or communication channel
impedance, or (c) changes in signal attributes (either
interrogating signals or subsequent signals) including changes in
signal amplitude, changes in signal phase, loss of signal, or
signal time delay.
When a single transducer is utilized, in the preferred embodiment
of the present invention, such transducer should be located at the
surface, and should be utilized to transmit a signal downward
within the communication channel (of the annulus). Typically, the
acoustic signal is reflected off of the drill collar portion of the
drillstring, and thus travels back upward through the communication
channel where it is received by the transducer which generated the
signal. In fact, any signal provided by the surface transducer will
travel a multiple number of times downward and then upward within
the communication channel as the signal repeatedly reflects off of
the drill collar portion of the drillstring. In one embodiment of
the present invention, one or more acoustic markers may be placed
within the drillstring at selected locations. Each member is
generally larger in diameter than the adjoining drillstring, and
provides a reflection surface at one or more known distances. The
reflection of acoustic signals off of these markers is monitored
for changes which indicate its presence of gas.
FIG. 25 graphically depicts a laboratory test of the transducer of
the present invention in a wellbore five hundred (500) feet deep.
In this figure, the X-axis is representative of the acoustic travel
path in units of time, which have been normalized to units of
length, and the Y-axis is representative of signal strength of the
signal received by the transducer which is disposed at the surface.
Peak 701 is representative of a signal which is generated by the
surface acoustic transceiver. At the termination of time interval
701, the first echo 705 is detected by the surface acoustic
transceiver. During this time interval, the acoustic signal has
traveled downward through the annulus, reflected from the drill
collar, and traveled back upward to the surface acoustic
transceiver for reception. At the termination of time interval 707,
the second acoustic signal 709 is received by the surface acoustic
transceiver. At the termination of time interval 711, the third
acoustic echo 713 is received by the surface acoustic transceiver.
At the termination of time interval 715, the fourth acoustic echo
717 is received by the surface acoustic transceiver. At the
termination of time interval 717, the fifth echo 719 is received by
the surface acoustic transceiver.
At the termination of time interval 719, the fifth echo 721 is
received by the surface acoustic transceiver. At the termination of
time interval 723, the sixth echo 725 is detected by the surface
acoustic transceiver. At the termination of time interval 727 the
seventh echo 729 is detected by the surface acoustic
transceiver.
Thus, it can be seen that if the annulus is unobstructed, a regular
pattern of echoes can be expected for acoustic signals emitted by
the surface acoustic transceiver. Each echo occurs at a
predetermined time on a time line, which corresponds to the
distance between the surface acoustic transceiver and tile drill
collar portion of the drillstring. Since the length of the
drillstring is known, and the frequency of transmission of the
acoustic signal is also known, the echoes occur as expected, unless
an obstruction exists within the annulus of the wellbore.
An influx of gas into the annulus can serve as an obstruction which
will cause the occurrence of echoes to be shifted in time. This
occurs, since the gas "slug" or "bubble" has different acoustic
transmission properties from the drilling mud, and will provide a
boundary from which reflection is expected. Thus, the generation of
an acoustic signal by the surface acoustic transceiver, and
subsequent monitoring of the return echoes, can be utilized to
detect (1) the presence of a gas influx, and (2) the location of a
gas influx. Assume for example that a gas bubble has entered the
annulus during drilling operations, and is located at a position
midway between the surface acoustic transceiver and the drill
collar. The expected result is an echo pattern which indicates a
travel path of approximately one-half of that which was previously
encountered during monitoring. The operator at the surface can
analyze the echo pattern and thus determine the presence and
location of the gas bubble.
In addition to monitoring the length of the communication channel,
the transducer and communication system of the present invention
may be utilized to detect the influx of gas by monitoring the
extent of amplitude attenuation in the echo signals as compared to
amplitude attenuation during periods of operation during which no
gas influx is present within the communication channel; said
monitoring is preferably not a calibrated measurement but is
instead a relative comparison of attenuation and the description
which follows utilizes the term "amplitude attenuation" in this
sense. With reference again to FIG. 25, the presence of undesirable
gas bubbles within the fluid column which comprises a communication
channel will result in a change in acoustic impedance of the fluid
column and will result in additional reflection losses. This change
in acoustic impedance of the fluid column will result in a change
in the amplitude attenuation of the signal as it echoes within the
wellbore by traveling downward and upward. For example, if a large
amount of gas is present within the communication channel, a
greater or lesser degree of signal attenuation may be observed than
is normally encountered during periods of operation during which no
gas is present within the communication channel. Therefore, by
continuously monitoring and comparing attenuation values, the
transducer of the present invention can be utilized to detect
changes in acoustic impedance which occur due to the influx of gas
within the communication channel. Any detected change in
communication channel length or impedance can be considered to be
detection of changes in "communication channel attributes".
Signals which are transmitted from the transducer can be monitored
for changes in amplitude, or significant time delays, both of which
could indicate the presence of an undesirable gas influx.
Additionally, signals which have been transmitted by the transducer
can be monitored for signal phase shift, which in an acoustic
transmission environment corresponds to significant transmission
delays (which are far greater than one wavelength).
The transducer and communication system of the present invention
may also be utilized during a gas influx detection mode of
operation, wherein the process of selection of the one or more
portions of available bandwidth for data communication is utilized
to detect changes in the communication channel which indicate that
a gas influx has occurred. As is shown in FIG. 26, surface acoustic
transceiver 743 may be coupled in a position at the surface to
communicate with annulus fluid 741 within wellbore 735. Drilling
rig 731 is provided to rotate drillstring 733. As is conventional,
drillstring 733 includes an upper section of drill pipe 737 and a
lower section of drill collar 739. Rockbit 738 disintegrates
geologic formations as drillstring 733 is rotated relative to
wellbore 735.
During selected portions of the drilling operations, surface
acoustic transceiver 743 (and associated personal computer monitor
745) is utilized to transmit interrogating signals downward into
wellbore 735 through annulus fluid 741, which is the communication
channel. One or more reflection markers may be provided and coupled
in position within drill pipe section 737 of drillstring 733.
Alternatively, the reflective boundary provided by drill collar 739
may be utilized as a reflection surface. Surface acoustic
transceiver 743 transmits either (a) a signal which includes a
number of signal components, each having a different frequency,
spanning a preselected frequency range, or (b) transmits a signal
having a fixed frequency. The signal is propagated downward through
annulus fluid 741, and reflects off of drill collar 739, and
returns toward the surface for reception by surface acoustic
transceiver 743.
If a signal is transmitted which includes a number of different
frequency components, the surface acoustic transceiver can analyze
the signal-to-noise attributes of various frequency portions over
the preselected frequency range to identify one or more optimal
bands within the frequency range, typically each being
approximately ten (10) Hertz wide, which are optimal at that time
for the communication of data within wellbore 735. The particular
optimal bands may be identified by upper and lower frequencies, or
a center frequency and a bandwidth. In either characterization, a
specific portion of a frequency range is identified as being
preferable to other portions of the frequency range for the
efficient transmission of data.
The introduction of an undesirable gas influx into the annulus
fluid 741 within wellbore 735 will alter the acoustic impedance of
the annulus fluid 741, and thus will alter the optimal frequency
portions for data transmission. Data can be obtained by continually
characterizing the communication channel of annulus fluid 741
during periods in which no gas influx is present within annulus
fluid 741. Subsequent characterizations of annulus fluid 741 can be
compared to the historical data to identify changes in the optimal
bandpass portions of the preselected frequency range to identify
the occurrence of a gas influx.
In FIG. 26, rockbit 738 is depicted as traversing a high pressure
gas zone 747. This causes a gas influx 749 to enter annulus fluid
741. Typically, gas influx 749 will enter annulus fluid 741 as a
"slug" of fluid. As it rises, it will come out of solution and
become a gas "bubble". The presence of either the fluid slug or the
gas bubble should cause a significant change in the optimal
operating frequencies for the communication channel of annulus
fluid 741. These abrupt changes in the optimal data transmission
frequencies should provide an indication to the operator at the
surface that an undesirable gas influx has occurred.
In alternative embodiments, one or more transducers may be located
within drillstring 733 for the transmission and/or reception of
acoustic signals. For example, downhole acoustic transceiver 740
may be provided in a position adjacent drill collar 739 for the
receipt or transmission of acoustic signals. In this configuration,
downhole acoustic transceiver 740 may be utilized, as was described
above in connection with the description of the data communication
system, to generate a characterizing signal which is detected by
surface acoustic transceiver 741, and processed by PC monitor 745,
also as was described above. Surface acoustic transceiver 743 and
downhole acoustic transceiver 740 may be utilized to transmit
signals back and forth across the communication channel of annulus
fluid 741. Changes in the communication channel, changes in signals
transmitted between surface acoustic transceiver 741 and downhole
acoustic transceiver 740, as well as changes in the optimal
communication frequencies can be utilized to detect the entry of an
undesirable gas influx 749. Echoes which are generated within the
communication channel of annulus fluid 741 which originate from
either the surface acoustic transceiver 743 or the downhole
acoustic transceiver 740 can be utilized to pinpoint the location
and size of a gas bubble as it travels upward within the annulus of
the wellbore.
The present invention can be utilized to monitor gas influx into a
well during drilling, and detect the event prior to the influx
bubble reaching the surface. This will greatly improve safety, by
preventing blowout of the well or other serious loss of control
situations. The system can be utilized to detect the position of
the top of the bubble. Since the transducer and communication
system of the present invention does not require that circulation
be present within the wellbore, the present invention can be
utilized to detect the influx of gas during quiescent periods
during which no fluid is being circulated within the wellbore, such
as tripping and casing operations. The present invention also
allows for the detection of small gas bubbles, far earlier than is
capable under conventional techniques. The present invention also
allows for significant changes to occur in the well during drilling
operations, such as changes in mud weight, and the subtraction or
addition of drillstring sections, since the system allows for
continuous monitoring of the communication channel to determine
optimum operating frequencies. This feature allows for the
automatic and continuous adjustment of the "baseline" performance
during significant reconfigurations of the wellbore, without
requiring any significant knowledge by the operator of acoustic
systems. In short, altered acoustic paths, disrupted acoustic
returns, disrupted frequency channels, and changes in the time of
flight as well as changes in amplitude relative to previous
amplitudes can be utilized separately or together to identify the
occurrence of an undesirable gas influx, and once the influx has
been detected, can be utilized to pinpoint the location, and
perhaps size, of the gas influx.
ALTERNATIVE DATA COMMUNICATION SYSTEM:
As an alternative to identifying specific and narrow portions of a
frequency band which provide optimal data transmission, the
communication system of the present invention can utilize an
opposite approach which utilizes a very broad band in its entirety
to transmit a corresponding binary character, such as a binary one,
and which uses another broad band to identify a corresponding
binary character, such as a binary zero. It has been shown by
Drumheller, in an article entitled "Acoustical Properties of
Drillstrings", Sandia National Laboratories, Paper No. SAND88-0502,
published in August of 1988, that acoustical signals of specific
frequencies travel from the bottom of a drillstring to the surface
with only small attenuation. These frequencies are contained within
frequency bands. Within these frequency bands there can be wide
variation of the attenuation of any one particular frequency, but
some or most of the frequencies within the band pass through the
drillstring notwithstanding dramatic changes in the wellbore
environment. Thus, selecting one particular frequency band as the
modulation frequency for a data transmission system ensures that
there is only a small probability that all frequencies within the
band will be attenuated and lost.
In accordance with the present invention, the communication channel
is in the wellbore, either a fluid column or a tubular member, is
analyzed to determine an optimal frequency band which may be
utilized to designate a particular binary value, such as a binary
"one", while another separate frequency band is identified to
represent the opposite binary character, such as a binary "zero".
For example, the communication channel is investigated to identify
a broad frequency band, such as five hundred ninety Hertz to six
hundred and ninety Hertz (590-690) which corresponds to a binary
"one", while it also investigated for a separate frequency band,
such as eight hundred and twenty Hertz to nine hundred and twenty
Hertz (820-920) which corresponds to a binary "zero".
The transducers of the present invention are utilized to generate
an acoustical signal which includes a plurality of signal portions,
each portion representing a different frequency within the band,
the portions altogether spanning the entire width of the selected
frequency band. For example, for the binary one, the acoustic
transducer will produce a signal which includes a plurality of
signal components spread across the five hundred ninety to six
hundred ninety (590-690) bandwidth. Likewise, for the binary
"zero", the transducer will generate an acoustical signal which
includes a plurality of signal components which span the range of
frequencies between eight hundred and twenty Hertz and nine hundred
and twenty Hertz (820-920).
During a reception mode of operation, the transducer, and
associated microprocessor computer, is utilized to analyze the
energy levels of acoustic signals detected in the separate
frequency band ranges. Preferably, the energy of the zero band is
compared to a baseline noise level which has previously been
obtained for the range of frequencies. Likewise, the energy level
of the frequency range representative of the binary "zero"0 is
compared with a baseline energy level previously acquired for the
same frequency range.
These concepts are illustrated in block diagram form in FIGS. 27
and 28, with FIG. 27 depicting the logic associated with the
transmitter, and FIG. 28 depicting the logic associated with the
receiver.
Referring first to FIG. 27A, sensor data is provided by sensors 801
to microprocessor 805 and digital storage memory 803. When
transmission of the data is desired, microprocessor 805 actuates
digital-to-analog converter 807 which generates an actuation signal
for binary "ones", and an actuation signal for binary "zeroes".
Power driver 809 generates a unique power signal associated with
each binary zero, and a unique power signal associated with each
binary one, as is depicted in graph 811, with a first preselected
range of frequencies representing a binary "one", and a second
preselected range of frequencies representing a binary "zero". In
the example of FIG. 27B, frequencies in the range of five hundred
ninety to six hundred and ninety Hertz (590-690) are representative
of the binary "one", while frequencies in the range of eight
hundred and twenty to nine hundred and twenty Hertz (820-920) are
representative of the binary "zero". This driving signal is
supplied to transducer 813 which is acoustically coupled to the
communication channel, which is preferably, but not necessarily, a
fluid column within the wellbore.
The acoustic signal is conducted to a remotely located transceiver,
such as transducer 815 of FIG. 28. The received acoustic signals
are amplified at amplifier 817, and supplied simultaneously to
bandpass filter 819 and bandpass filter 829. In the example of
FIGS. 27A, 27B and 28, bandpass filter 819 is a bandpass filter
which allows for the passage of frequencies in the range of five
hundred ninety to six hundred and ninety (590-690) Hertz, while
bandpass filter 829 allows for the passage of frequencies in the
range of eight hundred and twenty Hertz to nine hundred and twenty
Hertz (820-920). The outputs of bandpass filters 819, 829 are
supplied to subsequent signal processing blocks.
More specifically, the output of bandpass filter 819 is supplied to
integrator 821 which provides as an output an indication of the
energy content of the signals in the range of frequencies
corresponding to the binary "one". Likewise, the output of bandpass
filter 829 is supplied to integrator 831 which provides as an
output an indication of the energy contained by the signals in the
range of frequencies corresponding to the binary "zero". Base band
integrator 823 is utilized to provide an indication of the energy
level contained within the range of frequencies corresponding to
the binary "one" during periods which no signal is present.
Likewise, base band integrator 833 is utilized to provide as an
output an indication of the energy contained within the frequency
band corresponding to the binary "zero" during periods of
inactivity. As is shown in FIG. 28, the output of integrator 821
and base band integrator 823 is supplied to summing amplifier 825.
Likewise, the output of integrator 831 and base band integrator 833
are supplied to summing amplifier 835.
The output of summing amplifiers 825, 835 are provided to a
comparator. If the output of summing amplifier 825 exceeds the
output of summing amplifier 835, then the output of comparator 827
is a binary "one"; however, if the output of summing amplifier 835
is greater than the output of summing amplifier 825, then the
output of comparator 827 is a binary "zero". In this manner, the
binary data provided as an output from microprocessor 805 (of FIG.
27) may be reconstructed at the output of comparator 827 in a
remotely located transceiver.
Of course, in the present invention, the transducer which is
described herein may be utilized as an acoustic signal generator.
Furthermore, the data communication system described herein may be
utilized to select the best range of frequencies for representing
the binary "one" and the binary "zero".
* * * * *